UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2003 or

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

For the transition period from ________ to ________.

Commission file numbers: 1-14323
333-93239-01

ENTERPRISE PRODUCTS PARTNERS L.P.
ENTERPRISE PRODUCTS OPERATING L.P.
(Exact name of registrants as specified in their charters)

Delaware		76-0568219
Delaware		76-0568220
(State or other jurisdiction of incorporation of organization)		(I.R.S. Employer Identification No.)

2727 North Loop West, Houston, Texas 77008-1037
(Address of principal executive offices) (Zip Code)

Registrants’ telephone number, including area code: (713) 880-6500

Indicate by check mark whether the registrants: (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

YES [X] NO [ ]

Indicate by check mark if either registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

YES [X] NO [ ]

There were 211,768,371 Common Units of Enterprise Products Partners L.P. outstanding at November 1, 2003. Enterprise Products Partners L.P.’s Common Units trade on the New York Stock Exchange under symbol “EPD.” Enterprise Products Operating L.P. is owned 98.9899% by its parent, EPD, and 1.0101% by the General Partner. No common equity securities of Enterprise Products Operating L.P. are publicly-traded.

EXPLANATORY NOTE

This report constitutes a combined quarterly report on Form 10-Q for Enterprise Products Partners L.P. (the “Company”)(Commission File No. 1-14323) and its 98.9899% owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”)(Commission File No. 333-93239-01). Since the Operating Partnership owns substantially all of the Company’s consolidated assets and conducts substantially all of the Company’s business and operations, the information set forth herein, except for Part I, Item 1, constitutes combined information for the Company and the Operating Partnership. In accordance with Rule 3-10 of Regulation S-X, Part I, Item 1 contains separate financial statements for the Company and the Operating Partnership.

ENTERPRISE PRODUCTS PARTNERS L.P.
ENTERPRISE PRODUCTS OPERATING L.P.
TABLE OF CONTENTS

		Page No.
Glossary
	PART I. FINANCIAL INFORMATION.

Item 1.	Financial Statements.
Item 1A.	Enterprise Products Partners L.P.	1
Item 1B.	Enterprise Products Operating L.P.	25

Item 2.	Management’s Discussion and Analysis of Financial Condition
	and Results of Operations.	46

Item 3.	Quantitative and Qualitative Disclosures about Market Risk.	67

Item 4.	Controls and Procedures.	68

	PART II. OTHER INFORMATION.

Item 6.	Exhibits and Reports on Form 8-K.	69

Signatures page		72

Glossary

The following abbreviations, acronyms or terms used in this Form 10-Q are defined below:


Acadian Gas	Acadian Gas, LLC and subsidiaries, acquired from Shell in April 2001
Accum. OCI	Accumulated Other Comprehensive Income (Loss), as applicable
BBtus	Billion British thermal units, a measure of heating value
Bcf	Billion cubic feet
BEF	Belvieu Environmental Fuels, an equity investment of EPOLP through September 2003. On September 30, 2003, BEF became a majority-owned consolidated subsidiary (see footnote 3 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report)
Belle Rose	Belle Rose NGL Pipeline LLC, an equity investment of EPOLP
BRF	Baton Rouge Fractionators LLC, an equity investment of EPOLP
BRPC	Baton Rouge Propylene Concentrator, LLC, an equity investment of EPOLP
Btu	British thermal unit, a measure of heating value
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CMAI	Chemical Market Associates, Inc.
Company	Enterprise Products Partners L.P. and its consolidated subsidiaries, including the
	Operating Partnership
Diamond-Koch	Refers to affiliates of Valero Energy Corporation and Koch Industries, Inc.
Dixie	Dixie Pipeline Company, an equity investment of EPOLP
EPCO	Enterprise Products Company (including its affiliates), an affiliate of the
	Company and our ultimate parent company
EPIK	EPIK Terminalling L.P. and EPIK Gas Liquids, LLC, collectively, an equity
	investment of EPOLP until March 1, 2003, after which time it became 100%
	owned by EPOLP
EPOLP	Enterprise Products Operating L.P., the operating subsidiary of the Company
	(also referred to as the “Operating Partnership”)
Evangeline	Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively,
	an equity investment of EPOLP
FASB	Financial Accounting Standards Board
Feedstock	A raw material required for an industrial process such as in petrochemical
	manufacturing
Forward sales contracts	The sale of a commodity or other product in a current period for delivery in a
	future period
GAAP	Generally Accepted Accounting Principles in the United States of America
General Partner	Enterprise Products GP, LLC, the General Partner of the Company and the
	Operating Partnership
La Porte	La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively, an equity
	investment of EPOLP
MBA	Mont Belvieu Associates, see “MBA acquisition” below
MBA acquisition	Refers to the acquisition of Mont Belvieu Associates’ remaining interest in the
	Mont Belvieu NGL fractionation facility in 1999
MBFC	Mississippi Business Finance Corporation
MBPD	Thousand barrels per day
Mid-America	Mid-America Pipeline Company, LLC (we acquired an indirect 98% interest in
	Mid-America in July 2002)
MMBtus	Million British thermal units, a measure of heating value
Mont Belvieu	Mont Belvieu, Texas
Mont Belvieu Storage II	Refers to NGL and petrochemical storage businesses located in Mont Belvieu
	that were acquired from Diamond-Koch
Mont Belvieu Splitter III	See “Splitter III”
Moody’s	Moody’s Investors Service
MTBE	Methyl tertiary butyl ether

Glossary (continued)


Nemo	Nemo Gathering Company, LLC, an equity investment of EPOLP
Neptune	Neptune Pipeline Company LLC, an equity investment of EPOLP
NGL or NGLs	Natural gas liquid(s)
NYMEX	New York Merchantile Exchange
NYSE	New York Stock Exchange
OPIS	Oil Price Information Service
Operating Partnership	Enterprise Products Operating L.P. and its subsidiaries
OTC	Olefins Terminal Corporation, an equity investment of the Company until August 1, 2003, after which time it became a consolidated subsidiary (see footnote 3 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report)
Promix	K/D/S Promix LLC, an equity investment of EPOLP
SEC	U.S. Securities and Exchange Commission
Seminole	Seminole Pipeline Company (we acquired an indirect 78.4% interest in Seminole
	in July 2002)
SFAS	Statement of Financial Accounting Standards issued by the FASB
Shell	Shell Oil Company, its subsidiaries and affiliates
Splitter III	Refers to the propylene fractionation facility we acquired from Diamond-Koch
Starfish	Starfish Pipeline Company LLC, an equity investment of EPOLP
Throughput	Refers to the physical movement of volumes through a pipeline
Toca-Western	Refers to natural gas processing and NGL fractionation assets acquired from
	Western Gas Resources, Inc.
Tri-States	Tri-States NGL Pipeline LLC, an equity investment of EPOLP
Venice	Refers to natural gas processing and NGL fractionation assets owned by VESCO
Unit	Refers to limited partner interests in the Company (i.e., Common, Subordinated
	and Special Units)
VESCO	Venice Energy Services Company, LLC, a cost method investment of EPOLP
Williams	The Williams Companies, Inc. and subsidiaries
Wilprise	Wilprise Pipeline Company, LLC, an equity investment of EPOLP through September 2003. On October 1, 2003, Wilprise became a majority-owned consolidated subsidiary (see our discussion of “Subsequent Events” in the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report)
1999 Trust	EPOLP 1999 Grantor Trust, a subsidiary of EPOLP

For definitions of other commonly used terms used in our industry, please refer to the “Glossary” section of our 2002 annual report on Form 10-K/A (Commission File No. 1-14323).

PART I. FINANCIAL STATEMENTS.
Item 1A. ENTERPRISE PRODUCTS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

ASSETS	September 30, 2003			December 31, 2002
Current Assets
Cash and cash equivalents (includes restricted cash of $14,655 at
September 30, 2003 and $8,751 at December 31, 2002)	$	54,887		$	22,568
Accounts and notes receivable - trade, net of allowance for doubtful accounts
of $20,372 at September 30, 2003 and $21,196 at December 31, 2002		372,984			399,187
Accounts receivable - affiliates		211			228
Inventories		181,098			167,369
Prepaid and other current assets		30,045			48,216

Total current assets		639,225			637,568
Property, Plant and Equipment, Net		2,920,641			2,810,839
Investments in and Advances to Unconsolidated Affiliates		334,872			396,993
Intangible assets, net of accumulated amortization of $36,332 at
September 30, 2003 and $25,546 at December 31, 2002		266,875			277,661
Goodwill		81,547			81,547
Deferred Tax Asset		10,763			15,846
Long-Term Receivables		5,792			12
Other Assets		22,031			9,806

Total	$	4,281,746		$	4,230,272

LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Current maturities of debt	$	15,000		$	15,000
Accounts payable - trade		70,904			67,283
Accounts payable - affiliates		28,045			40,772
Accrued gas payables		476,580			489,562
Accrued expenses		24,504			35,760
Accrued interest		14,893			30,338
Other current liabilities		58,229			42,641

Total current liabilities		688,155			721,356
Long-Term Debt		1,874,577			2,231,463
Other Long-Term Liabilities		15,717			7,666
Minority Interest		98,018			68,883
Commitments and Contingencies
Partners’ Equity
Common Units (211,768,371 Units outstanding at September 30, 2003
and 141,694,766 at December 31, 2002)		1,600,555			949,835
Subordinated Units (32,114,804 Units outstanding at December 31, 2002)					116,288
Special Units (10,000,000 Units outstanding at December 31, 2002)					143,926
Treasury Units acquired by Trust, at cost (798,958 Units outstanding
at September 30, 2003 and 859,200 Units at December 31, 2002)		(16,533	)		(17,808	)
General Partner		16,167			12,223
Accumulated Other Comprehensive Income (Loss)		5,090			(3,560	)

Total Partners’ Equity		1,605,279			1,200,904

Total	$	4,281,746		$	4,230,272

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED OPERATIONS
AND COMPREHENSIVE INCOME
(Dollars in thousands, except per Unit amounts)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
REVENUES
Third parties	$	1,044,044		$	794,642		$	3,484,134		$	2,040,700
Related parties		190,736			148,671			442,891			350,924

Total		1,234,780			943,313			3,927,025			2,391,624

COST AND EXPENSES
Operating costs and expenses
Third parties		1,004,563			709,454			3,115,864			1,811,826
Related parties		174,140			159,208			583,573			467,043
Selling, general and administrative
Third parties		203			6,170			8,386			10,084
Related parties		7,212			6,119			20,553			17,907

Total		1,186,118			880,951			3,728,376			2,306,860

EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES		(18,040	)		5,963			(16,647	)		22,258

OPERATING INCOME		30,622			68,325			182,002			107,022

OTHER INCOME (EXPENSE)
Interest expense		(32,559	)		(30,690	)		(107,750	)		(68,235	)
Dividend income from unconsolidated affiliates		156						4,551			2,196
Interest income - other		223			434			587			2,009
Other, net		77			133			(15	)		357

Other income (expense)		(32,103	)		(30,123	)		(102,627	)		(63,673	)

INCOME (LOSS) BEFORE PROVISION FOR INCOME
TAXES AND MINORITY INTEREST		(1,481	)		38,202			79,375			43,349
PROVISION FOR INCOME TAXES		(1,023	)		(2,056	)		(4,628	)		(2,056	)

INCOME (LOSS) BEFORE MINORITY INTEREST		(2,504	)		36,146			74,747			41,293
MINORITY INTEREST		(757	)		(1,296	)		(4,398	)		(1,326	)

NET INCOME (LOSS)		(3,261	)		34,850			70,349			39,967
Reclassification of change in value of financial instruments
recorded as cash flow hedges								3,560
Gain on settlement of financial instruments recorded as cash flow hedges								5,354
Amortization of gain on settlement of financial instruments to earnings		(99	)					(264	)

COMPREHENSIVE INCOME (LOSS)	$	(3,360	)	$	34,850		$	78,999		$	39,967


ALLOCATION OF NET INCOME (LOSS) TO:
Limited partners	$	(8,273	)	$	32,076		$	56,123		$	33,299

General partner	$	5,012		$	2,774		$	14,226		$	6,668

BASIC EARNINGS PER UNIT
Income (loss) before minority interest	$	(0.04	)	$	0.21		$	0.31		$	0.23

Net income (loss) per Common and Subordinated unit	$	(0.04	)	$	0.20		$	0.29		$	0.22

DILUTED EARNINGS PER UNIT
Income (loss) before minority interest	$	(0.04	)	$	0.19		$	0.30		$	0.20

Net income (loss) per Common, Subordinated
and Special unit	$	(0.04	)	$	0.18		$	0.28		$	0.19

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in thousands)

	For the Nine Months Ended September 30,
	2003			2002
OPERATING ACTIVITIES
Net income	$	70,349		$	39,967
Adjustments to reconcile net income to cash flows provided
by (used for) operating activities:
Depreciation and amortization in operating costs and expenses		83,761			58,491
Depreciation in selling, general and administrative costs		83			55
Amortization in interest expense		12,237			4,361
Equity in loss (income) of unconsolidated affiliates		16,647			(22,258	)
Distributions received from unconsolidated affiliates		25,703			40,114
Operating lease expense paid by EPCO		6,752			6,782
Other expenses paid by EPCO		605
Minority interest		4,398			1,326
Loss (gain) on sale of assets		(67	)		6
Deferred income tax expense		4,182			529
Changes in fair market value of financial instruments		(25	)		12,830
Net effect of changes in operating accounts		3,944			27,906

Operating activities cash flows		228,569			170,109

INVESTING ACTIVITIES
Capital expenditures		(97,968	)		(46,958	)
Proceeds from sale of assets		177			18
Business combinations, net of cash received		(26,255	)		(1,615,298	)
Acquisition of intangible asset					(2,000	)
Investments in and advances to unconsolidated affiliates		(29,414	)		(13,193	)

Investing activities cash flows		(153,460	)		(1,677,431	)

FINANCING ACTIVITIES
Borrowings under debt agreements		1,326,210			1,883,000
Repayments of debt		(1,683,000	)		(270,000	)
Debt issuance costs		(7,773	)		(16,522	)
Distributions paid to partners		(223,416	)		(150,674	)
Distributions paid to minority interests		(7,202	)		(1,650	)
Contributions from minority interests		5,601			109
Proceeds from issuance of Common Units		540,154
Treasury Units purchased					(12,788	)
Treasury Units reissued		1,282
Settlement of treasury lock financial instruments		5,354
Increase in restricted cash		(5,904	)		(1,521	)

Financing activities cash flows		(48,694	)		1,429,954

NET CHANGE IN CASH AND CASH EQUIVALENTS		26,415			(77,368	)
CASH AND CASH EQUIVALENTS, JANUARY 1		13,817			132,071

CASH AND CASH EQUIVALENTS, SEPTEMBER 30	$	40,232		$	54,703

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY
(Dollars in thousands, see Note 9 for Unit History)

	Limited Partners
	Common Units			Subord. Units			Special Units			Treasury Units			General Partner			Accum. OCI			Total
Balance, December 31, 2002	$	949,835		$	116,288		$	143,926		$	(17,808	)	$	12,223		$	(3,560	)	$	1,200,904
Net income		45,557			10,566									14,226						70,349
Operating leases paid by EPCO		5,933			751									68						6,752
Other expenses paid by EPCO		598												6						604
Cash distributions to partners		(177,177	)		(30,482	)								(15,757	)					(223,416	)
Proceeds from issuance of
Common Units in January 2003		253,107												2,557						255,664
Proceeds from issuance of
Common Units in June 2003		256,001												2,586						258,587
Proceeds from issuance of
Common Units in connection
with DRP in August 2003		25,765												260						26,025
Proceeds from August 2003 issuance of
Common Units in connection with:
- EUPP		156												1						157
- EPCO Unit option plan		644												6						650
Reissuance of Treasury Units
to satisfy EPCO Unit option
plan in August 2003		7									1,275									1,282
Conversion of 10.7 million EPCO
Subordinated Units to
Common Units		97,123			(97,123	)
Conversion of 10.0 million
Shell Special Units to
Common Units		143,926						(143,926	)
Retirement of Common Units		(629	)											(6	)					(635	)
Treasury Lock financial instruments
recorded as cash flow hedges:
- Reclassification of change in
fair value																	3,560			3,560
- Cash gains on settlement																	5,354			5,354
- Amortization of gain as component
of interest expense																	(264	)		(264	)
Other		(291	)											(3	)					(294	)

Balance, September 30, 2003	$	1,600,555		$	-		$	-		$	(16,533	)	$	16,167		$	5,090		$	1,605,279

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

In the opinion of Enterprise Products Partners L.P., the accompanying unaudited consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of its:

•

consolidated financial position as of September 30, 2003;

•

consolidated results of operations for the three and nine months ended September 30, 2003 and 2002;

•

consolidated cash flows for the nine months ended September 30, 2003 and 2002; and

•

consolidated partners’ equity for the nine months ended September 30, 2003.

Within these footnote disclosures of Enterprise Products Partners L.P., references to “we”, “us”, “our” or “the Company” shall mean the consolidated financial statements of Enterprise Products Partners L.P.

References to “Operating Partnership” shall mean the consolidated financial statements of our primary operating subsidiary, Enterprise Products Operating L.P., which are included elsewhere in this combined quarterly report on Form 10-Q. We own 98.9899% of the Operating Partnership and act as guarantor of certain of its debt obligations. Our General Partner, Enterprise Products GP, LLC, owns the remaining 1.0101% of the Operating Partnership. Essentially all of our assets, liabilities, revenues and expenses are recorded at the Operating Partnership level in our consolidated financial statements.

Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the SEC. These unaudited financial statements should be read in conjunction with our annual report on Form 10-K/A (File No. 1-14323) for the year ended December 31, 2002.

The results of operations for the three and nine months ended September 30, 2003 are not necessarily indicative of the results to be expected for the full year.

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars, unless otherwise indicated.

Certain abbreviated entity names and other capitalized and industry terms are defined within the glossary of this quarterly report on Form 10-Q.

Certain reclassifications have been made to the prior years’ financial statements to conform to the current year presentation. These reclassifications had no effect on previously reported results of consolidated operations.

See Note 13 for the pro forma effect on net income and earnings per Unit if we had used the fair-value based method of accounting for Unit options.

2. RECENTLY ISSUED ACCOUNTING STANDARDS

SFAS No. 143, “Accounting for Asset Retirement Obligations.” We adopted this standard as of January 1, 2003. This statement establishes accounting standards for the recognition and measurement of an asset retirement obligation (“ARO”) liability and the associated asset retirement cost. Our adoption of this standard had no material impact on our financial statements. For a discussion regarding our implementation of this new standard, see Note 5.

SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” We adopted provisions of this standard as of January 1, 2003. This statement revised accounting guidance related to the extinguishment of debt and accounting for certain lease transactions. It also

amended other accounting literature to clarify its meaning, applicability and to make various technical corrections. Our adoption of this standard has had no material impact on our financial statements.

SFAS No. 146, “Accounting for Costs Associated with Exit and Disposal Activities.” We adopted this standard as of January 1, 2003. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of an entity’s commitment to an exit or disposal plan. Our adoption of this standard has had no material impact on our financial statements.

SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” We adopted this standard as of December 31, 2002. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. We have provided the information required by this statement under Note 13. Apart from this additional footnote disclosure, our adoption of this standard has had no material impact on our financial statements.

SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies accounting guidance for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We adopted SFAS No. 149 on a prospective basis as of July 1, 2003. Our adoption of this standard has had no material impact on our financial statements.

SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” This standard establishes classification and measurement standards for financial instruments with characteristics of both liabilities and equity. It requires an issuer of such financial instruments to reclassify the instrument from equity to a liability or an asset. The effective date of this standard for us was July 1, 2003. Our adoption of this standard has had no material impact on our financial statements.

FIN 45, “Guarantor’s Accounting and Disclosure Requirement from Guarantees, Including Indirect Guarantees of Indebtedness of Others.” We implemented this FASB interpretation as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We have provided the information required by this interpretation under Note 8.

FIN 46, “Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51.” This interpretation of ARB No. 51 addresses requirements for accounting consolidation of a variable interest entity (“VIE”) with its primary beneficiary. In general, if an equity owner of a VIE meets certain criteria defined within FIN 46, the assets, liabilities and results of the activities of the VIE should be included in the consolidated financial statements of the owner. Our adoption of FIN 46 as of January 31, 2003 has had no material effect on our financial statements.

3. BUSINESS COMBINATIONS

During the first nine months of 2003, we acquired EPIK’s remaining 50% ownership interest, the Port Neches Pipeline, and an additional 33.33% interest in BEF. In addition, we began consolidating the financial statements of OTC beginning August 2003 as a result of our obtaining control over this entity. We also made minor adjustments to the allocation of the purchase price we paid to acquire indirect interests in Mid-America and Seminole pipelines. Due to the immaterial nature of each transaction or event, individually and in the aggregate, our discussion of each of these transactions is limited to the following:

Acquisition of remaining 50% interest in EPIK. In March 2003, we purchased the remaining 50% ownership interests in EPIK. EPIK owns an NGL export terminal located in southeast Texas on the Houston Ship

Channel. As a result of this acquisition, EPIK became a consolidated wholly-owned subsidiary of ours (previously, it had been an equity-method unconsolidated affiliate).

Acquisition of Port Neches Pipeline. In March 2003, we acquired entities owning the Port Neches Pipeline (formerly known as the Quest Pipeline). The 70-mile Port Neches Pipeline transports high-purity grade isobutane produced at our facilities in Mont Belvieu to customers in Port Neches, Texas.

Acquisition of 33.33% interest in BEF. At the end of September 2003, we acquired an additional 33.33% partnership interest in BEF, which owns a facility that currently produces MTBE (a motor gasoline additive that enhances octane and is used in reformulated gasoline). Due to this acquisition, BEF became a majority-owned consolidated subsidiary of ours on September 30, 2003. Previously, BEF was accounted for as an equity-method unconsolidated affiliate.

Consolidation of OTC. In August 2003, we became the operator of OTC’s above ground polymer grade propylene storage and export facility located in Seabrook, Texas. We currently own 50% of OTC and represent its major customer. As a result of obtaining significant control over OTC through our operator, owner and customer relationship with the facility, we began consolidating OTC’s financial statements with ours beginning August 1, 2003. Previously, OTC was accounted for as an equity-method unconsolidated affiliate.

Other purchase price adjustments. We made purchase price adjustments relating to our $1.2 billion acquisition of indirect interests in the Mid-America and Seminole pipelines. These adjustments total a net $4.8 million and primarily relate to liabilities existing at July 31, 2002, which was the closing date of the acquisitions.

The following table shows our allocation of the purchase price for 2003 acquisitions, effects of consolidating entities that were formerly accounted for under the equity-method, and adjustments to purchase price allocations from prior periods.

	2003 Business Acquisitions			Consolidation of OTC			Other Purchase Price Adjustments			Total
Cash and cash equivalents	$	18,562		$	665					$	19,227
Accounts receivable		7,819			740		$	(172	)		8,387
Inventories		10,593									10,593
Prepaid and other current assets		5,114			62			(1,525	)		3,651
Property, plant and equipment, net		85,087			4,946			20,930			110,963
Investments in and advances to
unconsolidated affiliates		(43,684	)		(5,501	)					(49,185	)
Other assets		4,989						(124	)		4,865
Accounts payable		(5,007	)		(635	)					(5,642	)
Accrued gas payables		(5,370	)								(5,370	)
Accrued expenses		(1,734	)		(137	)		(1,887	)		(3,758	)
Other current liabilities		(4,329	)		(140	)		(11,449	)		(15,918	)
Other liabilities		(5,001	)					(1,062	)		(6,063	)
Minority interest		(26,437	)					169			(26,268	)

Total net assets recorded		40,602			-			4,880			45,482
Investee cash balances
recorded upon consolidation		(18,562	)		(665	)					(19,227	)

Business combinations, net of
cash received	$	22,040		$	(665	)	$	4,880		$	26,255

4. INVENTORIES

Our inventories were as follows at the dates indicated:

	September 30, 2003		December 31, 2002
Regular inventory	$	156,993	$	131,769
Forward-sales inventory		24,105		35,600

Inventory	$	181,098	$	167,369

Our regular inventory is comprised of inventories of NGLs, certain petrochemical products, and natural gas that are available for sale through our marketing activities. The forward sales inventory is comprised of segregated NGL volumes dedicated to the fulfillment of forward sales contracts.

Due to fluctuating market conditions in the midstream energy industry in which we operate, we occasionally recognize lower of cost or market (“LCM”) adjustments when the costs of our inventories exceed their net realizable value. These non-cash adjustments are charged to operating costs and expenses in the period they are recognized. For the three and nine months ended September 30, 2003, we recognized $0.7 million and $15.1 million, respectively, of such LCM adjustments. For the three and nine months ended September 30, 2002, we recognized $1.5 million and $6.2 million, respectively, of these adjustments. The majority of these write-downs were taken against NGL inventories.

5. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment and accumulated depreciation were as follows at the dates indicated:

	Estimated Useful Life in Years	September 30, 2003		December 31, 2002
Plants and pipelines	5-35	$	3,098,701	$	2,860,180
Underground and other storage facilities	5-35		296,548		283,114
Transportation equipment	3-35		5,586		5,118
Land			24,040		23,817
Construction in progress			105,770		49,586

Total			3,530,645		3,221,815
Less accumulated depreciation			610,004		410,976

Property, plant and equipment, net		$	2,920,641	$	2,810,839

Depreciation expense for the three months ended September 30, 2003 and 2002 was $24.7 million and $20.7 million, respectively. For the nine months ended September 30, 2003 and 2002, it was $73.1 million and $48.6 million, respectively.

Asset retirement obligations. SFAS No. 143 establishes accounting standards for the recognition and measurement of an ARO liability and the associated asset retirement cost. Under the implementation guidelines of SFAS No. 143, we reviewed our long-lived assets for ARO liabilities and identified such liabilities in several operational areas. These include ARO liabilities related to (i) right-of-way easements over property not owned by us and (ii) regulatory requirements triggered by the abandonment or retirement of certain currently operated facilities.

foreseeable future. Therefore, an ARO liability is not estimable for such easements. Should we decide not to renew these right-of-way agreements, an ARO liability would be recorded at that time. We also identified potential ARO liabilities arising from regulatory requirements related to the future abandonment or retirement of certain currently operated facilities. At present, we currently have no intention or legal obligation to abandon or retire such facilities. An ARO liability would be recorded if future abandonment or retirement of such facilities occurred.

Certain Gulf of Mexico natural gas pipelines owned by our equity method investees, Starfish, Neptune and Nemo, have identified ARO’s relating to regulatory requirements. At present, these entities have no plans to abandon or retire their major transmission pipelines; however, there are plans to retire certain minor gas gathering lines periodically through 2013. Should the management of these companies decide to abandon or retire their major transmission pipelines, an ARO liability would be recorded at that time. With regard to the minor gas gathering pipelines scheduled for retirement, Starfish and Neptune collectively recorded ARO liabilities during 2003 totaling $2.8 million (on a gross basis).

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

We own interests in a number of related businesses that are accounted for under the equity or cost methods. The investments in and advances to these unconsolidated affiliates are grouped according to the business segment to which they relate. For a general discussion of our business segments, see Note 12. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated:

			September 30, 2003		December 31, 2002
Accounted for on equity basis:
Fractionation:
BRF	32	.25%	$	27,853	$	28,293
BRPC	30	.00%		16,668		17,616
Promix	33	.33%		39,919		41,643
La Porte	50	.00%		5,334		5,737
OTC (1)	50	.00%		n/a		2,178
Pipeline:
EPIK (1)	50	.00%		n/a		11,114
Wilprise (1)	37	.35%		8,215		8,566
Tri-States (1)	33	.33%		25,074		25,552
Belle Rose	41	.67%		10,666		11,057
Dixie	19	.88%		37,383		36,660
Starfish	50	.00%		40,566		28,512
Neptune	25	.67%		75,299		77,365
Nemo	33	.92%		12,231		12,423
Evangeline	49	.50%		2,664		2,383
Octane Enhancement:
BEF (1)	33	.33%		n/a		54,894
Accounted for on cost basis:
Processing:
VESCO	13	.10%		33,000		33,000

Total			$	334,872	$	396,993


(1) See Notes 3 and 15 for a discussion of changes in ownership or control.

The following table shows our equity in income (loss) of unconsolidated affiliates for the periods indicated:

	Ownership			For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	Percentage			2003			2002			2003			2002
Fractionation:
BRF		32	.25%	$	227		$	719		$	308		$	2,011
BRPC		30	.00%		231			264			773			791
Promix		33	.33%		676			1,175			1,270			3,214
La Porte		50	.00%		(159	)		(134	)		(493	)		(399	)
OTC		50	.00%		(57	)		79			(77	)		97
Pipelines:
EPIK		50	.00%					435			1,818			2,064
Wilprise		37	.35%		83			267			276			734
Tri-States		33	.33%		52			645			1,176			1,479
Belle Rose		41	.67%		(20	)		74			(137	)		188
Dixie		19	.88%		366			(138	)		739			423
Starfish		50	.00%		781			499			3,265			2,284
Neptune		25	.67%		541			504			1,235			1,964
Nemo		33	.92%		326			369			920			391
Evangeline		49	.50%		108			51			144			(20	)
Octane Enhancement:
BEF		33	.33%		(21,195	)		1,154			(27,864	)		7,037

Total				$	(18,040	)	$	5,963		$	(16,647	)	$	22,258

The following tables present summarized income statement information for our unconsolidated affiliates accounted for under the equity method (for the periods indicated, on a 100% basis). We have grouped this information by the business segment to which the entities relate.

	Summarized Income Statement Information for the Three Months Ended
	September 30, 2003								September 30, 2002
	Revenues		Operating Income (Loss)			Net Income (Loss)			Revenues		Operating Income (Loss)		Net Income (Loss)
Pipelines	$	98,997	$	12,650		$	8,770		$	79,903	$	12,379	$	10,277
Fractionation		17,485		3,217			3,222			21,180		6,874		6,842
Octane Enhancement		48,255		(63,608	)		(63,585	)		61,501		3,393		3,466

	Summarized Income Statement Information for the Nine Months Ended
	September 30, 2003								September 30, 2002
	Revenues		Operating Income (Loss)			Net Income (Loss)			Revenues		Operating Income (Loss)		Net Income (Loss)
Pipelines	$	282,878	$	42,010		$	30,788		$	210,789	$	36,569	$	29,987
Fractionation		53,028		7,053			6,998			60,360		18,719		18,686
Octane Enhancement		134,543		(83,677	)		(83,592	)		167,562		20,940		21,113

Our initial investment in Promix, La Porte, Dixie, Neptune and Nemo exceeded our share of the historical cost of the underlying net assets of such entities (the “excess cost”). The excess cost of these investments is reflected in our investments in and advances to unconsolidated affiliates for these entities. That portion of excess cost attributable to the tangible plant and/or pipeline assets of each entity is amortized against equity earnings from these entities in a manner similar to depreciation. That portion of excess cost attributable to goodwill is subject to periodic impairment testing and is not amortized.

The following table summarizes our excess cost information at September 30, 2003 and December 31, 2002 by the business segment to which the unconsolidated affiliates relate:

		Original Excess Cost attributable to				Unamortized balance at
	Amort. Periods	Tangible assets		Goodwill		September 30, 2003		December 31, 2002
Fractionation	20-35 years	$	8,828			$	7,152	$	7,429
Pipelines	35 years (1)		41,943	$	9,246		46,735		47,637


(1) Goodwill is not amortized; however, it is subject to periodic impairment testing.

For each of the three months ended September 30, 2003 and 2002, we recorded $0.4 million of excess cost amortization, which is reflected in our equity in earnings from unconsolidated affiliates. We recorded $1.2 million of excess cost amortization for each of the nine month periods ended September 30, 2003 and 2002.

Purchase of remaining 50% interest in EPIK

As discussed in Note 3, we purchased the remaining 50% ownership interest in EPIK in March 2003. As a result of this acquisition, EPIK became a consolidated wholly-owned subsidiary. We recorded $1.8 million of equity income from EPIK for the two months that it was an unconsolidated subsidiary during the first quarter of 2003.

Purchase of an additional 33.33% interest in BEF

As discussed in Note 3, we purchased an additional 33.33% partnership interest in BEF on September 30, 2003. As a result of this acquisition, BEF became a majority-owned consolidated subsidiary of ours. Prior to this acquisition and consolidation, our share of BEF’s losses for the first nine months of 2003 was $27.9 million, which reflects an impairment charge recorded by BEF prior to our purchase of the additional partnership interest.

BEF owns a facility that currently produces MTBE, a motor gasoline additive that enhances octane and is used in reformulated gasoline. The production of MTBE is primarily driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990. As a result of environmental concerns, several states have enacted legislation to ban or significantly limit the use of MTBE in motor gasoline within their jurisdictions. In addition, federal legislation has been drafted to ban MTBE and replace the oxygenate with renewable fuels such as ethanol.

As a result of declining domestic demand and a prolonged period of weak MTBE production economics, several of BEF’s competitors have announced their withdrawal from the marketplace. Due to the deteriorating business environment and outlook and the completion of its preliminary engineering studies regarding conversion alternatives, BEF evaluated the carrying value of its long-lived assets for impairment during the third quarter of 2003. This review indicated that the carrying value of its long-lived assets exceeded their collective fair value, which resulted in a non-cash impairment charge of $67.5 million. Our share of this loss is $22.5 million and is recorded as a component of “Equity in income (loss) of unconsolidated affiliates” in our Statements of Consolidated Operations and Comprehensive Income for the three and nine months ended September 30, 2003. Our historical equity (and in the future, consolidated) earnings from BEF are classified under the Octane Enhancement business segment.

BEF’s assets were written down to fair value, which was determined by independent appraisers using present value techniques. The impaired assets principally represent the plant facility and other assets associated with MTBE production. The fair value analysis incorporates future courses of action being taken (or contemplated to be taken) by BEF management, including modification of the facility to produce iso-octane and alkylate. If the underlying assumptions in the fair value analysis change resulting in expected future cash flows being less than the new carrying value of the facility, additional impairment charges may result in the future.

BEF is currently in the process of preparing detailed engineering plans to convert the facility to iso-octane production. The project is expected to be complete by mid-2004. The facility will continue to produce MTBE as market conditions warrant and will be capable of producing either MTBE or iso-octane once the plant modifications are complete. Depending on the outcome of various factors (including pending federal legislation) the facility may be further modified in the future to produce alkylate.

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

The following table summarizes our intangible assets at September 30, 2003 and December 31, 2002:

			At September 30, 2003					At December 31, 2002
	Gross Value		Accum. Amort.			Carrying Value		Accum. Amort.			Carrying Value
Shell natural gas processing agreement	$	206,216	$	(31,301	)	$	174,915	$	(23,015	)	$	183,201
Mont Belvieu Storage II contracts		8,127		(407	)		7,720		(232	)		7,895
Mont Belvieu Splitter III contracts		53,000		(2,524	)		50,476		(1,388	)		51,612
Toca-Western natural gas processing contracts		11,187		(745	)		10,442		(326	)		10,861
Toca-Western NGL fractionation contracts		20,042		(1,336	)		18,706		(585	)		19,457
Venice contracts		4,635		(19	)		4,616					4,635

Total	$	303,207	$	(36,332	)	$	266,875	$	(25,546	)	$	277,661

The following table shows amortization expense associated with our intangible assets for the three and nine months ended September 30, 2003 and 2002:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2003		2002		2003		2002
Shell natural gas processing agreement	$	2,762	$	2,763	$	8,286	$	8,286
Mont Belvieu Storage II contracts		58		58		174		178
Mont Belvieu Splitter III contracts		379		379		1,137		1,010
Toca-Western natural gas processing contracts		140		185		420		185
Toca-Western NGL fractionation contracts		250		334		750		334
Venice contracts		19				19

Total	$	3,608	$	3,719	$	10,786	$	9,993

Goodwill

Our goodwill is attributable to the excess of the purchase price over the fair value of assets acquired and is comprised of the following (at September 30, 2003 and December 31, 2002):

Mont Belvieu Splitter III acquisition	$	73,690
MBA acquisition		7,857

	$	81,547

Our goodwill amounts are recorded as part of the Fractionation segment since they are related to assets classified within this operating segment.

8. DEBT OBLIGATIONS

Our debt obligations consisted of the following at the dates indicated:

	September 30, 2003			December 31, 2002
Borrowings under:
364-Day Term Loan, variable rate, due July 2003				$	1,022,000
364-Day Revolving Credit facility, variable rate,
due November 2004					99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005	$	145,000			225,000
Senior Notes A, 8.25% fixed rate, due March 2005		350,000			350,000
Seminole Notes, 6.67% fixed rate, $15 million due
each December, 2002 through 2005		45,000			45,000
MBFC Loan, 8.70% fixed rate, due March 2010		54,000			54,000
Senior Notes B, 7.50% fixed rate, due February 2011		450,000			450,000
Senior Notes C, 6.375% fixed rate, due February 2013		350,000
Senior Notes D, 6.875% fixed rate, due March 2033		500,000

Total principal amount		1,894,000			2,245,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt		1,591			1,774
Less unamortized discount on:
Senior Notes A		(53	)		(81	)
Senior Notes B		(208	)		(230	)
Senior Notes D		(5,753	)
Less current maturities of debt		(15,000	)		(15,000	)

Long-term debt	$	1,874,577		$	2,231,463

Letters of credit. At September 30, 2003 and December 31, 2002, we had $75 million of standby letter of credit capacity under our Multi-Year Revolving Credit facility. We had $13.9 million of letters of credit outstanding under this facility at September 30, 2003 and $2.4 million outstanding at December 31, 2002.

Parent-Subsidiary guarantor relationships. We act as guarantor of all of our Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes. If the Operating Partnership were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its ownership interests).

New senior notes issued during first quarter of 2003

During the first quarter of 2003, we completed the issuance of $850 million of long-term senior notes (Senior Notes C and D). Senior Notes C and D are unsecured obligations of our Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness. We guarantee both Senior Notes C and D for our subsidiary through an unsecured and unsubordinated guarantee that is non-recourse to the General Partner. These notes were issued under an indenture containing certain covenants and are subject to a make-whole redemption right if we elect to call the debt prior to its scheduled maturity. These covenants restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

Senior Notes C. In January 2003, we issued $350 million in principal amount of 6.375% fixed-rate senior notes due February 1, 2013 (“Senior Notes C”), from which we received net proceeds before offering expenses of approximately $347.7 million. These private placement notes were sold at face value with no discount or premium. We used the proceeds from this offering to repay a portion of the indebtedness outstanding under the 364-Day Term Loan that we incurred to finance the Mid-America and Seminole acquisitions. In May 2003, we exchanged 100% of the private placement Senior Notes C for publicly-registered Senior Notes C.

Senior Notes D. In February 2003, we issued $500 million in principal amount of 6.875% fixed-rate senior notes due March 1, 2033 (“Senior Notes D”), from which we received net proceeds before offering expenses of approximately $489.8 million. These private placement notes were sold at 98.842% of their face amount. We used $421.4 million from this offering to repay the remaining principal balance outstanding under the 364-Day Term Loan. In addition, we applied $60.0 million of the proceeds to reduce the balance outstanding under the 364-Day Revolving Credit facility. The remaining proceeds were used for working capital purposes. In July 2003, we exchanged 100% of the private placement Senior Notes D for publicly-registered Senior Notes D.

Repayment of 364-Day Term Loan

In July 2002, our Operating Partnership entered into the $1.2 billion senior unsecured 364-Day Term Loan to fund the acquisition of indirect interests in Mid-America and Seminole. We used $178.5 million of the $182.5 million in proceeds from our October 2002 equity offering to partially repay this loan. We also used $252.8 million of the $258.2 million in proceeds from the January 2003 equity offering (see Note 9), $347.0 million of the $347.7 million in proceeds from our issuance of Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes D to completely repay the 364-Day Term Loan in February 2003.

Revolving credit facilities

We used $60.0 million in proceeds from the issuance of Senior Notes D in February 2003 to reduce the balance outstanding under our 364-Day Revolving Credit facility. In addition, we applied $261.2 million of the net proceeds from our June 2003 equity offering (see Note 9) to reduce the balances then outstanding under our revolving credit facilities, of which $102 million was applied against the 364-Day Revolving Credit facility and $159.2 million against the Multi-Year Revolving Credit facility.

At September 30, 2003, we had $230 million of stand-alone borrowing capacity available under our 364-Day Revolving Credit facility, with no principal balance outstanding. In addition, we had $270 million in stand-alone borrowing capacity available under our Multi-Year Revolving Credit facility at September 30, 2003. We had $145 million of principal and $13.9 million in letters of credit outstanding under this facility at that date, with $111.1 million of unused capacity.

The original credit line available under our 364-Day Revolving Credit facility was set to expire in November 2003. In late October 2003, we refinanced the term of this facility. See Note 15 for additional information regarding this subsequent event.

Information regarding variable interest rates paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable-rate debt obligations for the nine months ended September 30, 2003:


364-Day Term Loan (a)	2.59% - 2.88%	2.85%
364-Day Revolving Credit facility	2.44% - 4.25%	2.52%
Multi-Year Revolving Credit facility	1.68% - 4.25%	1.89%


(a) This facility was repaid in February 2003.

9. CAPITAL STRUCTURE

Our Common Units represent, and prior to their conversion to Common Units on August 1 2003, our, Subordinated Units and convertible Special Units represented limited partner interests in the Company. We are managed by our General Partner. The rights available to our partners are described in the Third Amended and Restated Agreement of Limited Partnership (together with any amendments thereto). Our Common Units trade on the NYSE under the symbol “EPD.”

We allocate earnings and related amounts to Common and Subordinated (prior to their conversion to Common Units on August 1, 2003) Unitholders and the General Partner in accordance with our partnership agreement. These classes of partnership interests are also entitled to receive cash distributions. For financial accounting and tax purposes, the Special Units (prior to their conversion to Common Units on August 1, 2003), were not allocated any portion of net income; however, for tax purposes, the Special Units were allocated a certain amount of depreciation.

In January 2003, we completed a public offering of 14,662,500 Common Units (including 1,912,500 Common Units sold pursuant to the underwriters’ over-allotment option) from which we received net proceeds before offering expenses of approximately $258.2 million, including our General Partner’s $5.2 million in capital contributions. We used $252.8 million of the proceeds from this offering to repay a portion of the indebtedness outstanding under our 364-Day Term Loan (see Note 8). The remaining proceeds were used for working capital purposes and offering expenses.

In June 2003, we completed a public offering of 11,960,000 Common Units (including 1,560,000 Common Units sold pursuant to the underwriters’ over-allotment option) from which we received net proceeds before offering expenses of approximately $261.9 million, including our General Partner’s $5.3 million in capital contributions. We used the net proceeds from this offering to reduce indebtedness outstanding under our revolving credit facilities (see Note 8). The remaining proceeds were used for offering expenses.

In August 2003, we issued 1,268,404 Common Units in connection with our distribution reinvestment plan from which we received net proceeds of approximately $26.0 million, including our General Partner’s $0.3 million in capital contributions. The proceeds from this offering were used for general partnership purposes. We also issued 67,897 Common Units as a result of equity-based awards and employee Common Unit purchases.

Our partnership agreement stipulated that the Subordinated Units would undergo an early conversion to Common Units if certain criteria were satisfied. As a result of meeting the necessary criteria, 10,704,936 of EPCO’s Subordinated Units converted to Common Units on May 1, 2003 and the remaining 21,409,868 Subordinated Units converted on August 1, 2003. These conversions have no impact upon our earnings per unit or distributions since Subordinated Units were already included in both the basic and fully-diluted earnings per unit calculations and are distribution-bearing.

On August 1, 2003, the last 10,000,000 of Shell’s non-distribution bearing Special Units converted to Common Units. The conversion affected basic earnings per Unit beginning with the third quarter of 2003. These units were already included in our fully-diluted earnings per Unit computations. Since Common Units are distribution-bearing, our limited partner cash distributions to Shell will increase beginning with the distribution we expect to make in November 2003.

The following table details Unit activity within each class of our limited partner interests during the nine months ended September 30, 2003:

	Limited Partners
	Common Units		Subordinated Units			Special Units			Treasury Units
Balance, December 31, 2002		141,694,766		32,114,804			10,000,000			859,200
Common Units issued in January 2003		14,662,500
Conversion of Subordinated Units
to Common Units in May 2003		10,704,936		(10,704,936	)
Common Units issued in June 2003		11,960,000
Conversion of Special Units
to Common Units in August 2003		10,000,000					(10,000,000	)
Conversion of Subordinated Units
to Common Units in August 2003		21,409,868		(21,409,868	)
Common Units issued for DRP in August 2003		1,268,404
Common Units issued for EUPP in August 2003		7,655
Common Units issued due to exercise of
options in August 2003		30,000
Reissuance of Treasury Units to satisfy exercise
of options in August 2003		30,242								(30,242	)
Retirement of Treasury Units in August 2003										(30,000	)

Balance, September 30, 2003		211,768,371		-			-			798,958

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

The net effect of changes in operating accounts is as follows for the periods indicated:

	For the Nine Months Ended September 30,
	2003			2002
(Increase) decrease in:
Accounts and notes receivable	$	34,613		$	(49,675	)
Inventories		18,861			(144,746	)
Prepaid and other current assets		10,256			16,183
Other assets		(72	)		(3,326	)
Increase (decrease) in:
Accounts payable		(14,677	)		54,198
Accrued gas payable		(18,353	)		170,407
Accrued expenses		(15,013	)		(5,884	)
Accrued interest		(15,446	)		(9,478	)
Other current liabilities		4,571			372
Other liabilities		(796	)		(145	)

Net effect of changes in operating accounts	$	3,944		$	27,906

During the first nine months of 2003, we completed three business acquisitions; made adjustments to the purchase price allocation of the Mid-America and Seminole acquisitions; and consolidated three entities that had been previously accounted for using the equity-method. These transactions and events affected various balance sheet accounts (see Note 3). The 2002 period reflects our acquisition of indirect interests in Mid-America and Seminole pipelines from Williams and propylene fractionation and NGL and petrochemical storage assets from Diamond-Koch.

We record certain financial instruments relating to commodity positions and interest rate hedging activities at their respective fair values using mark-to-market accounting. For the nine months ended September 30, 2002, we recognized a net $12.8 million in non-cash mark-to-market decreases in the fair value of these instruments, primarily in our commodity financial instruments portfolio. We had a limited number of such positions outstanding during the first nine months of 2003, with the non-cash change in fair value of these instruments being an increase of $25 thousand.

Cash and cash equivalents (as shown on our Statements of Consolidated Cash Flows) exclude restricted cash held by a brokerage firm both as margin deposits associated with our financial instruments portfolio and cash deposits pertaining to physical natural gas purchase transactions we made on the NYMEX exchange. The restricted cash balance at September 30, 2003 and December 31, 2002 was $14.7 million and $8.8 million, respectively.

During the second quarter of 2003, we recognized a $6.7 million long-term receivable from a customer relating to the construction of certain pipeline equipment. Of this amount, $3.9 million relates to charges originally recorded as construction-in-progress and $2.8 million represents deferred revenue classified as a component of other liabilities. This receivable is expected to be collected over the next ten years and bears an effective annual interest rate of approximately 12%.

Certain of our expenses are paid by EPCO, which are accounted for as non-cash related party expenses in our Statements of Consolidated Operations and Comprehensive Income (with an offset to Partners’ Equity on the Consolidated Balance Sheets recorded as a general contribution to the Company). These expenses include (i) operating leases for which EPCO has retained the corresponding cash lease payment obligation and (ii) administrative service costs incurred by EPCO on behalf of us in excess of our actual cash reimbursement to EPCO. For the nine months ended September 30, 2003 and 2002, operating leases paid by EPCO totaled $6.8 million for each period. EPCO’s unreimbursed administrative service costs for the three and nine months ended September 30, 2003 were $0.6 million.

11. FINANCIAL INSTRUMENTS

We are exposed to financial market risks, including changes in commodity prices and interest rates. We may use financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions, primarily within our Processing segment. In general, the types of risks we attempt to hedge are those relating to the variability of future earnings and cash flows caused by changes in commodity prices and interest rates. As a matter of policy, we do not use financial instruments for speculative (or trading) purposes.

Commodity hedging financial instruments

During the first nine months of 2002, we recognized a loss of $52.3 million from our Processing segment’s commodity hedging activities that was recorded as an operating cost in our Statements of Consolidated Operations and Comprehensive Income. Of this loss, $1.4 million was recorded during the third quarter of 2002. In March 2002, the effectiveness of our primary commodity hedging strategy deteriorated due to an unexpected rapid increase in natural gas prices whereby the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002.

During the first nine months of 2003, we utilized a limited number of commodity financial instruments from which we recorded a loss of $0.9 million. Of this loss amount, $6 thousand was recognized during the third quarter of 2003. The fair value of open positions at September 30, 2003 was a nominal payable amount.

Interest rate hedging financial instruments

in early 2003 to refinance the Mid-America and Seminole acquisitions. The notional amounts of the treasury lock transactions totaled $550 million, with a total treasury lock rate of approximately 4%.

These transactions were accounted for as cash flow hedges under SFAS No. 133. The fair value of these financial instruments at December 31, 2002 was a current liability of $3.8 million offset by a current asset of $0.2 million. The net $3.6 million non-cash mark-to-market liability was recorded as a component of comprehensive income on that date, with no impact on 2002 net income.

We settled all of the treasury locks in early February 2003 in connection with our issuance of Senior Notes C and D (see Note 8). The settlement of these financial instruments resulted in our receipt of $5.4 million in cash. This amount was recorded as a gain in other comprehensive income during the first quarter of 2003 and represents the effective portion of the treasury locks.

Of the $5.4 million recorded in other comprehensive income during the first quarter of 2003, $4.0 million is attributable to our issuance of Senior Notes C and is being amortized to earnings as a reduction in interest expense over the 10-year term of this debt. The remaining $1.4 million is attributable to our issuance of Senior Notes D and is being amortized to earnings as a reduction in interest expense over the 10-year term of the anticipated transaction as required by SFAS No. 133. The estimated amount to be reclassified from accumulated other comprehensive income to earnings during 2003 is $0.4 million. As a result of settlement of the treasury locks, the $3.6 million non-cash mark-to-market liability recorded at December 31, 2002 was reclassified out of accumulated other comprehensive income in Partners’ Equity to offset the current asset and liability we recorded at December 31, 2002 with no impact on 2003 net income.

12. SEGMENT INFORMATION

We have five reportable business (or operating) segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. Our reportable segments are generally organized according to the type of services rendered (or process employed) and products produced and/or sold, as applicable. The segments are regularly evaluated by the CEO of the General Partner. Pipelines consists of NGL, petrochemical and natural gas pipeline systems, storage and import/export terminal services. Fractionation primarily includes NGL fractionation, isomerization, and polymer-grade and chemical-grade propylene fractionation services. Processing includes the natural gas processing business and its related NGL marketing activities. Octane Enhancement represents our investment in BEF, a facility that produces motor gasoline additives to enhance octane (currently producing MTBE). The Other business segment consists of fee-based marketing services and various operational support activities.

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. We define total segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the payment obligation; (3) gains and losses on the sale of assets; and (4) selling, general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions. In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation.

Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This non-GAAP financial measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses. The GAAP measure most directly comparable to total segment gross operating margin is operating income.

The following table shows our measurement of total segment gross operating margin for the periods indicated:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
Revenues (a)	$	1,234,780		$	943,313		$	3,927,025		$	2,391,624
Less operating costs and expenses (a)		(1,178,703	)		(868,662	)		(3,699,437	)		(2,278,869	)
Add equity in income (loss) of unconsolidated affiliates (b)		(18,040	)		5,963			(16,647	)		22,258

Subtotal		38,037			80,614			210,941			135,013
Add: Depreciation and amortization in operating costs and expenses (c)		28,259			24,292			83,761			58,491
Retained lease expense, net in operating expenses allocable to us (d)		2,250			2,248			6,752			6,782
Retained lease expense, net in operating expenses allocable to
our General Partner’s minority interest in us (e)		23			26			68			70
Loss (gain) on sale of assets in operating costs and expenses (c)		(35	)		(6	)		(67	)		6

Total segment gross operating margin	$	68,534		$	107,174		$	301,455		$	200,362


(a) These amounts are comprised of both third-party and related party totals as shown on our Statements of Consolidated Operations and Comprehensive Income.
(b) This amount is taken directly from our Statements of Consolidated Operations and Comprehensive Income.
(c) This amount is taken directly from the operating activities section of our Statements of Consolidated Cash Flows.
(d) This non-cash amount represents our share of the value of the operating leases contributed by EPCO to the Operating Partnership for which EPCO has retained the cash payment obligation (the “retained leases”). This amount is taken from the operating activities section (“Operating lease expense paid to EPCO” line item) of our Statements of Consolidated Cash Flows.
(e) This non-cash amount represents a minority interest holder’s share of the value of the retained leases. This amount is a component of “Contributions from minority interests” as shown in the financing activities section of our Statements of Consolidated Cash Flows.

The following table reconciles GAAP operating income as shown on our Statements of Consolidated Operations and Comprehensive Income to total segment gross operating margin for the periods indicated:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
Operating income	$	30,622		$	68,325		$	182,002		$	107,022
Adjustments to reconcile operating income
to total gross operating margin:
Depreciation and amortization in operating costs and expenses		28,259			24,292			83,761			58,491
Retained lease expense, net in operating costs and expenses		2,273			2,274			6,820			6,852
Loss (gain) on sale of assets in operating costs and expenses		(35	)		(6	)		(67	)		6
Selling, general and administrative costs		7,415			12,289			28,939			27,991

Total segment gross operating margin	$	68,534		$	107,174		$	301,455		$	200,362

Information by business segment, together with reconciliations to the consolidated totals, is presented in the following table:

	Operating Segments													Adjs.
	Fractionation		Pipelines		Processing			Octane Enhancement			Other			and Elims.			Consol. Totals
Revenues from third parties:
Three months ended September 30, 2003	$	182,559	$	94,833	$	766,039					$	613					$	1,044,044
Three months ended September 30, 2002		173,304		121,717		499,251						370						794,642
Nine months ended September 30, 2003		582,582		477,109		2,422,526						1,917						3,484,134
Nine months ended September 30, 2002		440,162		296,929		1,302,431						1,178						2,040,700

Revenues from related parties:
Three months ended September 30, 2003		744		115,524		74,468												190,736
Three months ended September 30, 2002		6,477		52,586		89,577						31						148,671
Nine months ended September 30, 2003		2,017		189,578		251,296												442,891
Nine months ended September 30, 2002		18,386		115,044		217,372						122						350,924

Intersegment and intrasegment revenues:
Three months ended September 30, 2003		52,570		32,915		225,136						101		$	(310,722	)
Three months ended September 30, 2002		59,737		27,469		123,049						100			(210,355	)
Nine months ended September 30, 2003		194,669		136,602		563,397						303			(894,971	)
Nine months ended September 30, 2002		149,237		77,557		390,278						302			(617,374	)

Total revenues:
Three months ended September 30, 2003		235,873		243,272		1,065,643						714			(310,722	)		1,234,780
Three months ended September 30, 2002		239,518		201,772		711,877						501			(210,355	)		943,313
Nine months ended September 30, 2003		779,268		803,289		3,237,219						2,220			(894,971	)		3,927,025
Nine months ended September 30, 2002		607,785		489,530		1,910,081						1,602			(617,374	)		2,391,624

Equity in income (loss) of unconsolidated
affiliates:
Three months ended September 30, 2003		918		2,237				$	(21,195	)								(18,040	)
Three months ended September 30, 2002		2,102		2,705					1,156									5,963
Nine months ended September 30, 2003		1,781		9,436					(27,864	)								(16,647	)
Nine months ended September 30, 2002		5,714		9,506					7,038									22,258

Gross operating margin by individual
business segment and in total:
Three months ended September 30, 2003		30,617		66,589		(6,884	)		(21,195	)		(593	)					68,534
Three months ended September 30, 2002		34,585		63,887		8,417			1,155			(870	)					107,174
Nine months ended September 30, 2003		95,535		210,490		25,757			(27,864	)		(2,463	)					301,455
Nine months ended September 30, 2002		92,815		128,745		(26,141	)		7,038			(2,095	)					200,362

Segment assets:
At September 30, 2003		438,751		2,148,423		164,233			39,105			24,359			105,770			2,920,641
At December 31, 2002		444,016		2,166,524		134,237						16,825			49,237			2,810,839

Investments in and advances
to unconsolidated affiliates:
At September 30, 2003		89,774		212,098		33,000												334,872
At December 31, 2002		95,467		213,632		33,000			54,894									396,993

Intangible Assets:
At September 30, 2003		69,182		7,720		189,973												266,875
At December 31, 2002		71,069		7,895		198,697												277,661

Goodwill:
At September 30, 2003 and
December 31, 2002		81,547																81,547

Our revenues are derived from a wide customer base. All consolidated revenues during the three and nine months ended September 30, 2003 and 2002 were earned in the United States. The increase in period-to-period revenues is primarily due to acquisitions and higher NGL, propylene and natural gas prices, both of which offset the effects of lower volumes at many of our pipelines and facilities.

For the three months ended September 30, 2003 and 2002, total segment gross operating margin was $68.5 million and $107.2 million, respectively. The $38.7 million decrease in gross operating margin for the 2003 period is primarily due to weaker Processing segment sales margins and propylene fractionation results and a $22.5 million impairment charge related to our investment in BEF, which more than offset higher earnings from the Pipelines segment. Our Pipelines segment benefited from acquisitions and increased demand for import-related services.

For the nine month periods ended September 30, 2003 and 2002, total segment gross operating margin was $301.5 million and $200.4 million, respectively. The primary reasons for the increase in total segment gross operating margin between the periods are (a) 2003 includes gross operating margin from Mid-America and Seminole (acquired in July 2002) and (b) 2002 includes significant commodity hedging losses (see Note 11). Mid-America and Seminole’s gross operating margin is classified under our Pipelines segment while commodity hedging results are primarily a function of our Processing segment activities.

Segment assets for Octane Enhancement totaled $39.1 million at September 30, 2003. This amount reflects the consolidation of BEF at that date due to our acquisition of an additional 33.33% ownership interest in BEF. As a result of this consolidation, our investment in and advances to BEF recorded under the Octane Enhancement segment was eliminated. The September 30, 2003 carrying value of segment assets related to BEF reflects the impairment charge noted previously. For additional information regarding our purchase of the additional interest in BEF, see Note 3. For additional information regarding BEF’s impairment charge, see Note 6.

13. UNIT OPTION PLAN ACCOUNTING

During 1998, EPCO adopted its 1998 Long-Term Incentive Plan (the “1998 Plan”). Under the 1998 Plan, non-qualified incentive options to purchase a fixed number of our Common Units (the “Units”) may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. The exercise price per Unit, vesting and expiration terms, and rights to receive distributions on Units granted are determined by EPCO for each grant. EPCO purchases Units under the 1998 Plan at fair value either in the open market or from us (in the form of newly-issued Common Units or reissued Treasury Units). In general, our responsibility for reimbursing EPCO for the cash outlay it incurs when these options are exercised is as follows:

•

We pay EPCO for the costs attributable to equity-based awards granted to operations personnel it employs on our behalf. Our payment to EPCO is in the form of a special distribution.

•

We pay EPCO for the costs attributable to equity-based awards granted to administrative and management personnel it hires in response to our expansion and business activities. Our payment to EPCO is in the form of a special distribution.

•

We pay EPCO for our share of the costs attributable to equity-based awards granted to certain of its employees in administrative and management positions that were active at the time of our initial public offering in July 1998 who manage our business and affairs. These costs are reimbursed through the administrative service fees we pay EPCO. EPCO is responsible for the actual costs of such awards when these options are exercised. To the extent that EPCO’s total administrative costs (including the cost of such equity-based awards) exceed the annual administrative service fees we pay to them, such excess costs will result in a charge against our earnings as a non-cash related party expense and a corresponding credit to Partners’ Equity recorded as a contribution.

We account for our share of the cost of these awards using the intrinsic value-based method in accordance with APB No. 25, “Accounting for Stock Issued to Employees.” The exercise price of each option granted is equivalent to or greater than the market price of the Unit at the date of grant. Accordingly, no compensation expense related to Unit option grants has been recognized in our Statements of Consolidated Operations and Comprehensive Income. Any special distributions that we make to reimburse EPCO are a component of “Cash distributions to partners” as shown in our Statements of Consolidated Partners’ Equity.

Accounting principles require us to illustrate the pro forma effect on our net income and earnings per Unit as if the fair value-based method of accounting (based on SFAS No. 123, “Accounting for Stock Based Compensation”) had been applied to the 1998 Plan. The following table shows these pro forma effects for the periods indicated:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
Historical net income (loss)	$	(3,261	)	$	34,850		$	70,349		$	39,967
Additional Unit option-based compensation
expense estimated using the fair
value-based method		(171	)		(273	)		(514	)		(820	)

Pro forma net income (loss)	$	(3,432	)	$	34,577		$	69,835		$	39,147


Basic net income (loss) per Unit:
As reported	$	(0.04)		$	0.20		$	0.29		$	0.22

Pro forma	$	(0.04)		$	0.20		$	0.28		$	0.22

Diluted net income (loss) per Unit:
As reported	$	(0.04)		$	0.18		$	0.28		$	0.19

Pro forma	$	(0.04)		$	0.18		$	0.27		$	0.19

14. EARNINGS PER UNIT

Basic earnings per Unit is computed by dividing net income available to limited partner interests by the weighted-average number of Common and Subordinated Units outstanding during a period. In general, diluted earnings per Unit is computed by dividing net income available to limited partner interests by the weighted-average number of Common, Subordinated, Special Units and incremental Common Units from the assumed exercise of dilutive Unit options outstanding during a period. In a period of net operating losses, the Special Units and incremental Common Units from the assumed exercise of dilutive Unit options are excluded from the calculation of diluted earnings per Unit due to their antidilutive effect (as occurred for the first quarter of 2002 and third quarter of 2003). Treasury Units are not considered to be outstanding Units; therefore, they are excluded from the computation of both basic and diluted earnings per Unit.

Dilutive potential Common Units are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the beginning of each period are used to repurchase Common Units at average market value during the period. The amount of Common Units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.

Beginning in August 2003, we issued new Common Units to satisfy the exercise of a small number of Unit options by the employees of EPCO (see Note 13). The issuance of new Common Units to satisfy EPCO’s Unit option liability has a dilutive effect on our earnings per Unit. Prior to August 2003, EPCO had purchased practically all of the Units associated with the 1998 Plan in the open market. As a result, EPCO’s Unit option plan did not have any effect on our fully diluted earnings per Unit in prior periods.

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
Income (loss) before minority interest	$	(2,504	)	$	36,146		$	74,747		$	41,293
General partner interest		(5,012	)		(2,774	)		(14,226	)		(6,668	)

Income (loss) before minority interest		(7,516	)		33,372			60,521			34,625
available to Limited Partners
Minority interest		(757	)		(1,296	)		(4,398	)		(1,326	)

Net income (loss) available to Limited Partners	$	(8,273	)	$	32,076		$	56,123		$	33,299


BASIC EARNINGS PER UNIT
Numerator
Income (loss) before minority interest
available to Limited Partners	$	(7,516	)	$	33,372		$	60,521		$	34,625

Net income (loss) available
to Limited Partners	$	(8,273	)	$	32,076		$	56,123		$	33,299

Denominator
Common Units outstanding		200,587			125,502			174,057			112,699
Subordinated Units outstanding		7,214			32,115			21,331			36,820

Total		207,801			157,617			195,388			149,519

Basic Earnings per Unit
Income (loss) before minority interest
available to Limited Partners	$	(0.04	)	$	0.21		$	0.31		$	0.23

Net income (loss) available
to Limited Partners	$	(0.04	)	$	0.20		$	0.29		$	0.22


DILUTED EARNINGS PER UNIT
Numerator
Income (loss) before minority interest
available to Limited Partners	$	(7,516	)	$	33,372		$	60,521		$	34,625

Net income (loss) available
to Limited Partners	$	(8,273	)	$	32,076		$	56,123		$	33,299

Denominator
Common Units outstanding		200,587			125,502			174,057			112,699
Subordinated Units outstanding		7,214			32,115			21,331			36,820
Special Units outstanding		n/a			16,402			7,766			24,755
Incremental Common Units from the assumed
exercise of dilutive Unit options		n/a			n/a			662			n/a

Total		207,801			174,019			203,816			174,274

Diluted Earnings per Unit
Income (loss) before minority interest
available to Limited Partners	$	(0.04	)	$	0.19		$	0.30		$	0.20

Net income (loss) available
to Limited Partners	$	(0.04	)	$	0.18		$	0.28		$	0.19

For the third quarter of 2003, the following securities were not included in the computation of diluted earnings per Unit as their effect would have been anti-dilutive (in thousands): Special Units, 3,370; Incremental Common Units from the assumed exercise of dilutive Unit options, 595.

15. SUBSEQUENT EVENTS

In October 2003, our Operating Partnership refinanced its 364-Day Revolving Credit facility. The credit line available under this facility now expires in October 2004. In accordance with terms of the new credit agreement, we have the option to convert any revolving credit balance outstanding at maturity to a one-year term loan (due October 2005). In connection with this refinancing, certain financial ratio covenants of our 364-Day and Multi-Year Revolving Credit facilities were amended to increase our financial flexibility.

In October 2003, we purchased from Williams an additional 37.35% interest in Wilprise and 16.67% interest in Tri-States. The initial purchase price of these interests was $26.5 million. As a result of these acquisitions, our ownership interest in Wilprise is now 74.7% and for Tri-States, 50%.

PART I. FINANCIAL STATEMENTS.
Item 1B. ENTERPRISE PRODUCTS OPERATING L.P.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)

ASSETS	September 30, 2003			December 31, 2002
Current Assets
Cash and cash equivalents (includes restricted cash of $14,655 at
September 30, 2003 and $8,751 at December 31, 2002)	$	54,742		$	20,795
Accounts and notes receivable - trade, net of allowance for doubtful accounts
of $20,372 at September 30, 2003 and $21,196 at December 31, 2002
		372,984			399,187
Accounts receivable - affiliates		633			3,369
Inventories		181,098			167,369
Prepaid and other current assets		29,940			48,137

Total current assets		639,397			638,857
Property, Plant and Equipment, Net		2,920,641			2,810,839
Investments in and Advances to Unconsolidated Affiliates		334,872			396,993
Intangible assets, net of accumulated amortization of $36,332 at
September 30, 2003 and $25,546 at December 31, 2002		266,875			277,661
Goodwill		81,547			81,547
Deferred Tax Asset		10,763			15,846
Long-term Receivables		5,792			12
Other Assets		22,031			9,806

Total	$	4,281,918		$	4,231,561

LIABILITIES AND PARTNERS’ EQUITY
Current Liabilities
Current maturities of debt	$	15,000		$	15,000
Accounts payable - trade		70,904			67,283
Accounts payable - affiliates		26,069			40,773
Accrued gas payables		476,580			489,562
Accrued expenses		23,638			35,760
Accrued interest		14,893			30,338
Other current liabilities		58,231			42,644

Total current liabilities		685,315			721,360
Long-Term Debt		1,874,577			2,231,463
Other Long-Term Liabilities		15,717			7,666
Minority Interest		84,413			59,336
Commitments and Contingencies
Partners’ Equity
Limited Partner		1,609,047			1,211,593
General Partner		16,419			12,363
Parent’s Units acquired by Trust		(8,660	)		(8,660	)
Accumulated Other Comprehensive Income (Loss)		5,090			(3,560	)

Total Partners’ Equity		1,621,896			1,211,736

Total	$	4,281,918		$	4,231,561

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS OPERATING L.P.
STATEMENTS OF CONSOLIDATED OPERATIONS
AND COMPREHENSIVE INCOME
(Dollars in thousands)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
REVENUES
Revenues from consolidated operations
Third parties	$	1,044,044		$	794,642		$	3,484,134		$	2,040,700
Related parties		190,736			148,671			442,891			350,924

Total		1,234,780			943,313			3,927,025			2,391,624

COST AND EXPENSES
Operating costs and expenses
Third parties		1,004,563			709,454			3,115,864			1,811,826
Related parties		174,140			159,208			583,573			467,043
Selling, general and administrative
Third parties		50			6,152			7,896			9,965
Related parties		7,212			6,119			20,553			17,907

Total		1,185,965			880,933			3,727,886			2,306,741

EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES		(18,040	)		5,963			(16,647	)		22,258

OPERATING INCOME		30,775			68,343			182,492			107,141

OTHER INCOME (EXPENSE)
Interest expense		(32,559	)		(30,690	)		(107,751	)		(68,235	)
Dividend income from unconsolidated affiliates		156						4,551			2,196
Interest income - other		377			576			1,036			2,396
Other, net		74			134			(15	)		247

Other income (expense)		(31,952	)		(29,980	)		(102,179	)		(63,396	)

INCOME (LOSS) BEFORE PROVISION FOR INCOME
TAXES AND MINORITY INTEREST		(1,177	)		38,363			80,313			43,745
PROVISION FOR INCOME TAXES		(1,023	)		(2,056	)		(4,628	)		(2,056	)

INCOME (LOSS) BEFORE MINORITY INTEREST		(2,200	)		36,307			75,685			41,689
MINORITY INTEREST		(808	)		(988	)		(3,767	)		(1,074	)

NET INCOME (LOSS)		(3,008	)		35,319			71,918			40,615
Reclassification of change in value of financial instruments
recorded as cash flow hedges								3,560
Gain on settlement of financial instruments recorded as cash flow hedges								5,354
Amortization of gain on settlement of financial instruments to earnings		(99	)					(264	)

COMPREHENSIVE INCOME (LOSS)	$	(3,107	)	$	35,319		$	80,568		$	40,615

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS OPERATING L.P.
STATEMENTS OF CONSOLIDATED CASH FLOW
(Dollars in thousands)

	For the Nine Months Ended September 30,
	2003			2002
OPERATING ACTIVITIES
Net income	$	71,918		$	40,615
Adjustments to reconcile net income to cash flows provided
by (used for) operating activities:
Depreciation and amortization in operating costs and expenses		83,761			58,491
Depreciation in selling, general and administrative costs		83			55
Amortization in interest expense		12,237			4,361
Equity in income (loss) of unconsolidated affiliates		16,647			(22,258	)
Distributions received from unconsolidated affiliates		25,703			40,114
Operating lease expense paid by EPCO		6,820			6,852
Other expenses paid by EPCO		611
Minority interest		3,767			1,074
Loss (gain) on sale of assets		(67	)		6
Deferred income tax expense		4,182			529
Changes in fair market value of financial instruments		(25	)		12,830
Net effect of changes in operating accounts		3,848			23,055

Operating activities cash flows		229,485			165,724

INVESTING ACTIVITIES
Capital expenditures		(97,968	)		(46,958	)
Proceeds from sale of assets		177			18
Business combinations, net of cash received		(26,255	)		(1,615,298	)
Acquisition of intangible asset					(2,000	)
Investments in and advances to unconsolidated affiliates		(29,414	)		(13,193	)

Investing activities cash flows		(153,460	)		(1,677,431	)

FINANCING ACTIVITIES
Borrowings under debt agreements		1,326,210			1,883,000
Repayments of debt		(1,683,000	)		(270,000	)
Debt issuance costs		(7,773	)		(16,522	)
Distributions paid to partners		(224,929	)		(159,510	)
Distributions paid to minority interests		(5,110	)		(173	)
Contributions from partners		547,090			39
Contributions from minority interests		80			1,324
Parent’s Units acquired by consolidated Trust					(2,439	)
Settlement of treasury lock financial instruments		5,354
Increase in restricted cash		(5,904	)		(1,521	)

Financing activities cash flows		(47,982	)		1,434,198

NET CHANGE IN CASH AND CASH EQUIVALENTS		28,043			(77,509	)
CASH AND CASH EQUIVALENTS, JANUARY 1		12,044			132,071

CASH AND CASH EQUIVALENTS, SEPTEMBER 30	$	40,087		$	54,562

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS OPERATING L.P.
STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY
(Dollars in thousands)

	Limited Partner			General Partner			Parent’s Units			Accum. OCI			Total
Balances, December 31, 2002	$	1,211,593		$	12,363		$	(8,660	)	$	(3,560	)	$	1,211,736
Net income		71,192			726									71,918
Operating leases paid by EPCO		6,751			69									6,820
Other expenses paid by EPCO		605			6									611
Contributions from partners		541,563			5,527									547,090
Cash distributions to partners		(222,657	)		(2,272	)								(224,929	)
Treasury Lock financial instruments
recorded as cash flow hedges:
- Reclassification of change in
fair value											3,560			3,560
- Cash gains on settlement											5,354			5,354
- Amortization of gain as component
of interest expense											(264	)		(264	)

Balances, September 30, 2003	$	1,609,047		$	16,419		$	(8,660	)	$	5,090		$	1,621,896

See Notes to Unaudited Consolidated Financial Statements

ENTERPRISE PRODUCTS OPERATING L.P.
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

In the opinion of Enterprise Products Operating L.P., the accompanying unaudited consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation of its:

•

consolidated financial position as of September 30, 2003;

•

consolidated results of operations for the three and nine months ended September 30, 2003 and 2002;

•

consolidated cash flows for the nine months ended September 30, 2003 and 2002; and

•

consolidated partners’equity for the nine months ended September 30, 2003.

Within these footnote disclosures of Enterprise Products Operating L.P., references to “we”, “us”, “our” or “the Company” shall mean the consolidated financial statements of Enterprise Products Operating L.P. References to “Limited Partner” shall mean the consolidated financial statements of our parent, Enterprise Products Partners L.P., which are included elsewhere in this combined quarterly report on Form 10-Q.

The results of operations for the three and nine months ended September 30, 2003 are not necessarily indicative of the results to be expected for the full year.

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars, unless otherwise indicated.

Certain abbreviated entity names and other capitalized and industry terms are defined within the glossary of this quarterly report on Form 10-Q.

See Note 13 for the pro forma effect on net income if we had used the fair-value based method of accounting for equity-based options.

2. RECENTLY ISSUED ACCOUNTING STANDARDS

SFAS No. 143, “Accounting for Asset Retirement Obligations.” We adopted this standard as of January 1, 2003. This statement establishes accounting standards for the recognition and measurement of an asset retirement obligation (“ARO”) liability and the associated asset retirement cost. Our adoption of this standard had no material impact on our financial statements. For a discussion regarding our implementation of this new standard, see Note 5.

SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” We adopted provisions of this standard as of January 1, 2003. This statement revised accounting guidance related to the extinguishment of debt and accounting for certain lease transactions. It also amended other accounting literature to clarify its meaning, applicability and to make various technical corrections. Our adoption of this standard has had no material impact on our financial statements.

disposal activities when they are incurred rather than at the date of an entity’s commitment to an exit or disposal plan. Our adoption of this standard has had no material impact on our financial statements.

SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” We adopted this standard as of December 31, 2002. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. We have provided the information required by this statement under Note 13. Apart from this additional footnote disclosure, our adoption of this standard has had no material impact on our financial statements.

SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies accounting guidance for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We adopted SFAS No. 149 on a prospective basis as of July 1, 2003. Our adoption of this standard has had no material impact on our financial statements.

SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” This standard establishes classification and measurement standards for financial instruments with characteristics of both liabilities and equity. It requires an issuer of such financial instruments to reclassify the instrument from equity to a liability or an asset. The effective date of this standard for us was July 1, 2003. Our adoption of this standard has had no material impact on our financial statements.

FIN 45, “Guarantor’s Accounting and Disclosure Requirement from Guarantees, Including Indirect Guarantees of Indebtedness of Others.” We implemented this FASB interpretation as of December 31, 2002. This interpretation of SFAS No. 5, 57 and 107, and rescission of FASB Interpretation No. 34 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. We have provided the information required by this interpretation under Note 8.

FIN 46, “Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51.” This interpretation of ARB No. 51 addresses requirements for accounting consolidation of a variable interest entity (“VIE”) with its primary beneficiary. In general, if an equity owner of a VIE meets certain criteria defined within FIN 46, the assets, liabilities and results of the activities of the VIE should be included in the consolidated financial statements of the owner. Our adoption of FIN 46 as of January 31, 2003 has had no material effect on our financial statements.

3. BUSINESS COMBINATIONS

Acquisition of remaining 50% interest in EPIK. In March 2003, we purchased the remaining 50% ownership interests in EPIK. EPIK owns an NGL export terminal located in southeast Texas on the Houston Ship Channel. As a result of this acquisition, EPIK became a consolidated wholly-owned subsidiary of ours (previously, it had been an equity-method unconsolidated affiliate).

	2003 Business Acquisitions			Consolidation of OTC			Other Purchase Price Adjustments			Total
Cash and cash equivalents	$	18,562		$	665					$	19,227
Accounts receivable		7,819			740		$	(172	)		8,387
Inventories		10,593									10,593
Prepaid and other current assets		5,114			62			(1,525	)		3,651
Property, plant and equipment, net		85,087			4,946			20,930			110,963
Investments in and advances to
unconsolidated affiliates		(43,684	)		(5,501	)					(49,185	)
Other assets		4,989						(124	)		4,865
Accounts payable		(5,007	)		(635	)					(5,642	)
Accrued gas payables		(5,370	)								(5,370	)
Accrued expenses		(1,734	)		(137	)		(1,887	)		(3,758	)
Other current liabilities		(4,329	)		(140	)		(11,449	)		(15,918	)
Other liabilities		(5,001	)					(1,062	)		(6,063	)
Minority interest		(26,437	)					169			(26,268	)

Total net assets recorded		40,602			-			4,880			45,482
Investee cash balances
recorded upon consolidation		(18,562	)		(665	)					(19,227	)

Business combinations, net of
cash received	$	22,040		$	(665	)	$	4,880		$	26,255

4. INVENTORIES

Our inventories were as follows at the dates indicated:

	September 30, 2003		December 31, 2002
Regular inventory	$	156,993	$	131,769
Forward-sales inventory		24,105		35,600

Inventory	$	181,098	$	167,369

5. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment and accumulated depreciation were as follows at the dates indicated:

	Estimated Useful Life in Years	September 30, 2003		December 31, 2002
Plants and pipelines	5-35	$	3,098,701	$	2,860,180
Underground and other storage facilities	5-35		296,548		283,114
Transportation equipment	3-35		5,586		5,118
Land			24,040		23,817
Construction in progress			105,770		49,586

Total			3,530,645		3,221,815
Less accumulated depreciation			610,004		410,976

Property, plant and equipment, net		$	2,920,641	$	2,810,839

As a result of our analysis of identified AROs, we were not required to recognize such potential liabilities. Our rights under the easements are renewable and only require retirement action upon nonrenewal of the easement agreements. We currently expect to renew all such easement agreements and to use these properties for the foreseeable future. Therefore, an ARO liability is not estimable for such easements. Should we decide not to renew these right-of-way agreements, an ARO liability would be recorded at that time. We also identified potential ARO liabilities arising from regulatory requirements related to the future abandonment or retirement of certain currently operated facilities. At present, we currently have no intention or legal obligation to abandon or retire such facilities. An ARO liability would be recorded if future abandonment or retirement of such facilities occurred.

pipelines scheduled for retirement, Starfish and Neptune collectively recorded ARO liabilities during 2003 totaling $2.8 million (on a gross basis).

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

			September 30, 2003		December 31, 2002
Accounted for on equity basis:
Fractionation:
BRF	32	.25%	$	27,853	$	28,293
BRPC	30	.00%		16,668		17,616
Promix	33	.33%		39,919		41,643
La Porte	50	.00%		5,334		5,737
OTC (1)	50	.00%		n/a		2,178
Pipeline:
EPIK (1)	50	.00%		n/a		11,114
Wilprise (1)	37	.35%		8,215		8,566
Tri-States (1)	33	.33%		25,074		25,552
Belle Rose	41	.67%		10,666		11,057
Dixie	19	.88%		37,383		36,660
Starfish	50	.00%		40,566		28,512
Neptune	25	.67%		75,299		77,365
Nemo	33	.92%		12,231		12,423
Evangeline	49	.50%		2,664		2,383
Octane Enhancement:
BEF (1)	33	.33%		n/a		54,894
Accounted for on cost basis:
Processing:
VESCO	13	.10%		33,000		33,000

Total			$	334,872	$	396,993


(1) See Notes 3 and 14 for a discussion of changes in ownership or control.

The following table shows our equity in income (loss) of unconsolidated affiliates for the periods indicated:

	Ownership			For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	Percentage			2003			2002			2003			2002
Fractionation:
BRF		32	.25%	$	227		$	719		$	308		$	2,011
BRPC		30	.00%		231			264			773			791
Promix		33	.33%		676			1,175			1,270			3,214
La Porte		50	.00%		(159	)		(134	)		(493	)		(399	)
OTC		50	.00%		(57	)		79			(77	)		97
Pipelines:
EPIK		50	.00%					435			1,818			2,064
Wilprise		37	.35%		83			267			276			734
Tri-States		33	.33%		52			645			1,176			1,479
Belle Rose		41	.67%		(20	)		74			(137	)		188
Dixie		19	.88%		366			(138	)		739			423
Starfish		50	.00%		781			499			3,265			2,284
Neptune		25	.67%		541			504			1,235			1,964
Nemo		33	.92%		326			369			920			391
Evangeline		49	.50%		108			51			144			(20	)
Octane Enhancement:
BEF		33	.33%		(21,195	)		1,154			(27,864	)		7,037

Total				$	(18,040	)	$	5,963		$	(16,647	)	$	22,258

	Summarized Income Statement Information for the Three Months Ended
	September 30, 2003								September 30, 2002
	Revenues		Operating Income (Loss)			Net Income (Loss)			Revenues		Operating Income (Loss)		Net Income (Loss)
Pipelines	$	98,997	$	12,650		$	8,770		$	79,903	$	12,379	$	10,277
Fractionation		17,485		3,217			3,222			21,180		6,874		6,842
Octane Enhancement		48,255		(63,608	)		(63,585	)		61,501		3,393		3,466

	Summarized Income Statement Information for the Nine Months Ended
	September 30, 2003								September 30, 2002
	Revenues		Operating Income (Loss)			Net Income (Loss)			Revenues		Operating Income (Loss)		Net Income (Loss)
Pipelines	$	282,878	$	42,010		$	30,788		$	210,789	$	36,569	$	29,987
Fractionation		53,028		7,053			6,998			60,360		18,719		18,686
Octane Enhancement		134,543		(83,677	)		(83,592	)		167,562		20,940		21,113

The following table summarizes our excess cost information at September 30, 2003 and December 31, 2002 by the business segment to which the unconsolidated affiliates relate:

		Original Excess Cost attributable to				Unamortized balance at
	Amort. Periods	Tangible assets		Goodwill		September 30, 2003		December 31, 2002
Fractionation	20-35 years	$	8,828			$	7,152	$	7,429
Pipelines	35 years (1)		41,943	$	9,246		46,735		47,637


(1) Goodwill is not amortized; however, it is subject to periodic impairment testing.

Purchase of remaining 50% interest in EPIK

Purchase of an additional 33.33% interest in BEF

As discussed in Note 3, we purchased an additional 33.33% partnership interest in BEF at the end of September 2003. As a result of this acquisition, BEF became a majority-owned consolidated subsidiary of ours. Prior to this acquisition and consolidation, our share of BEF’s losses for the first nine months of 2003 was $27.9 million, which reflects an impairment charge recorded by BEF prior to our purchase of the additional partnership interest.

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

The following table summarizes our intangible assets at September 30, 2003 and December 31, 2002:

			At September 30, 2003					At December 31, 2002
	Gross Value		Accum. Amort.			Carrying Value		Accum. Amort.			Carrying Value
Shell natural gas processing agreement	$	206,216	$	(31,301	)	$	174,915	$	(23,015	)	$	183,201
Mont Belvieu Storage II contracts		8,127		(407	)		7,720		(232	)		7,895
Mont Belvieu Splitter III contracts		53,000		(2,524	)		50,476		(1,388	)		51,612
Toca-Western natural gas processing contracts		11,187		(745	)		10,442		(326	)		10,861
Toca-Western NGL fractionation contracts		20,042		(1,336	)		18,706		(585	)		19,457
Venice contracts		4,635		(19	)		4,616					4,635

Total	$	303,207	$	(36,332	)	$	266,875	$	(25,546	)	$	277,661

The following table shows amortization expense associated with our intangible assets for the three and nine months ended September 30, 2003 and 2002:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2003		2002		2003		2002
Shell natural gas processing agreement	$	2,762	$	2,763	$	8,286	$	8,286
Mont Belvieu Storage II contracts		58		58		174		178
Mont Belvieu Splitter III contracts		379		379		1,137		1,010
Toca-Western natural gas processing contracts		140		185		420		185
Toca-Western NGL fractionation contracts		250		334		750		334
Venice contracts		19				19

Total	$	3,608	$	3,719	$	10,786	$	9,993

Goodwill

Our goodwill is attributable to the excess of the purchase price over the fair value of assets acquired and is comprised of the following (at September 30, 2003 and December 31, 2002):

Mont Belvieu Splitter III acquisition	$	73,690
MBA acquisition		7,857

	$	81,547

Our goodwill amounts are recorded as part of the Fractionation segment since they are related to assets classified within this operating segment.

8. DEBT OBLIGATIONS

Our debt obligations consisted of the following at the dates indicated:

	September 30, 2003			December 31, 2002
Borrowings under:
364-Day Term Loan, variable rate, due July 2003				$	1,022,000
364-Day Revolving Credit facility, variable rate,
due November 2004					99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005	$	145,000			225,000
Senior Notes A, 8.25% fixed rate, due March 2005		350,000			350,000
Seminole Notes, 6.67% fixed rate, $15 million due
each December, 2002 through 2005		45,000			45,000
MBFC Loan, 8.70% fixed rate, due March 2010		54,000			54,000
Senior Notes B, 7.50% fixed rate, due February 2011		450,000			450,000
Senior Notes C, 6.375% fixed rate, due February 2013		350,000
Senior Notes D, 6.875% fixed rate, due March 2033		500,000

Total principal amount		1,894,000			2,245,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt		1,591			1,774
Less unamortized discount on:
Senior Notes A		(53	)		(81	)
Senior Notes B		(208	)		(230	)
Senior Notes D		(5,753	)
Less current maturities of debt		(15,000	)		(15,000	)

Long-term debt	$	1,874,577		$	2,231,463

Covenants. We were in compliance with the various covenants of our debt agreements at September 30, 2003 and December 31, 2002. Certain financial ratio covenants of our revolving credit facilities were amended in connection with the refinancing of our 364-Day Revolving Credit facility in October 2003 (see Note 14).

Parent-Subsidiary guarantor relationships. Our parent (which is our Limited Partner) is the guarantor of certain of our consolidated debt obligations. This parent-subsidiary guaranty provision exists under all of our consolidated debt obligations, with the exception of the Seminole Notes. If we were to default on any debt guaranteed by the Limited Partner, our Limited Partner would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its ownership interests).

New senior notes issued during first quarter of 2003

During the first quarter of 2003, we completed the issuance of $850 million of long-term senior notes (Senior Notes C and D). Senior Notes C and D are unsecured obligations and rank equally with our existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness. Senior Notes C and D are guaranteed by our Limited Partner through an unsecured and unsubordinated guarantee that is non-recourse to the General Partner. These notes were issued under an indenture containing certain covenants and are subject to a make-whole redemption right if we elect to call the debt prior to its scheduled maturity. These covenants restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

Repayment of 364-Day Term Loan

In July 2002, we entered into the $1.2 billion senior unsecured 364-Day Term Loan to fund the acquisition of indirect interests in Mid-America and Seminole. We used $178.5 million of the $182.5 million in proceeds from our Limited Partner’s October 2002 equity offering to partially repay this loan. We also used $252.8 million of the $258.2 million in proceeds from our Limited Partner’s January 2003 equity offering (see Note 9), $347.0 million of the $347.7 million in proceeds from our issuance of Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes D to completely repay the 364-Day Term Loan in February 2003.

Revolving credit facilities

We used $60.0 million in proceeds from the issuance of Senior Notes D in February 2003 to reduce the balance outstanding under our 364-Day Revolving Credit facility. In addition, we applied $261.2 million in contributions related to our Limited Partner’s June 2003 equity offering (see Note 9) to reduce the balances then outstanding under our revolving credit facilities, of which $102 million was applied against the 364-Day Revolving Credit facility and $159.2 million against the Multi-Year Revolving Credit facility.

The original credit line available under our 364-Day Revolving Credit facility was set to expire in November 2003. In late October 2003, we refinanced the term of this facility. See Note 14 for additional information regarding this subsequent event.

Information regarding variable interest rates paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable-rate debt obligations for the nine months ended September 30, 2003:


364-Day Term Loan (a)	2.59% - 2.88%	2.85%
364-Day Revolving Credit facility	2.44% - 4.25%	2.52%
Multi-Year Revolving Credit facility	1.68% - 4.25%	1.89%


(a) This facility was repaid in February 2003.

9. CAPITAL STRUCTURE

We are owned 98.9899% by our Limited Partner and 1.0101% by our General Partner. The rights available to our partners are described in the Amended and Restated Agreement of Limited Partnership. We are managed by our General Partner.

In January 2003, our Limited Partner completed an equity offering from which we received a cash contribution of $258.2 million, which includes our General Partner’s related capital contribution of $2.6 million. We used $252.8 million of the contribution to repay a portion of the indebtedness outstanding under the 364-Day Term Loan. The remaining balance of the contribution was used for working capital purposes.

In June 2003, our Limited Partner completed an equity offering from which we received a cash contribution of $261.2 million, which includes our General Partner’s related capital contribution of $2.6 million. We used the proceeds from this contribution to reduce indebtedness outstanding under our revolving credit facilities.

In August 2003, our Limited Partner contributed $27.4 million to us in connection with proceeds received primarily from its distribution reinvestment plan. The General Partner contributed $0.3 million. We used the cash received for general partnership purposes.

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

The net effect of changes in operating accounts is as follows for the periods indicated:

	For the Nine Months Ended September 30,
	2003			2002
(Increase) decrease in:
Accounts and notes receivable	$	37,332		$	(50,948	)
Inventories		18,861			(144,746	)
Prepaid and other current assets		10,283			16,183
Other assets		(72	)		(3,326	)
Increase (decrease) in:
Accounts payable		(16,654	)		50,393
Accrued gas payable		(18,353	)		170,407
Accrued expenses		(15,879	)		(5,657	)
Accrued interest		(15,446	)		(9,478	)
Other current liabilities		4,571			372
Other liabilities		(795	)		(145	)

Net effect of changes in operating accounts	$	3,848		$	23,055

Certain of our expenses are paid by EPCO, which are accounted for as non-cash related party expenses in our Statements of Consolidated Operations and Comprehensive Income (with an offset to Partners’ Equity on the Consolidated Balance Sheets recorded as a general contribution to the Company). These expenses include (i) operating leases for which EPCO has retained the corresponding cash lease payment obligation and (ii) administrative service costs incurred by EPCO on behalf of us in excess of our actual cash reimbursement to EPCO. For the nine months ended September 30, 2003 and 2002, operating leases paid by EPCO totaled $6.8 million and $6.9 million, respectively. EPCO’s unreimbursed administrative service costs for the three and nine months ended September 30, 2003 were $0.6 million.

11. FINANCIAL INSTRUMENTS

Commodity hedging financial instruments

Interest rate hedging financial instruments

During the fourth quarter of 2002, we entered into seven treasury lock transactions. Each treasury lock transaction carried a maturity date of either January 31, 2003 or April 15, 2003. The purpose of these financial instruments was to hedge the underlying U.S. treasury interest rate associated with our anticipated issuance of debt in early 2003 to refinance the Mid-America and Seminole acquisitions. The notional amounts of the treasury lock transactions totaled $550 million, with a total treasury lock rate of approximately 4%.

12. SEGMENT INFORMATION

The following table shows our measurement of total segment gross operating margin for the periods indicated:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
Revenues (a)	$	1,234,780		$	943,313		$	3,927,025		$	2,391,624
Less operating costs and expenses (a)		(1,178,703	)		(868,662	)		(3,699,437	)		(2,278,869	)
Add equity in income (loss) of unconsolidated affiliates (b)		(18,040	)		5,963			(16,647	)		22,258

Subtotal		38,037			80,614			210,941			135,013
Add: Depreciation and amortization in operating costs and expenses (c)		28,259			24,292			83,761			58,491
Retained lease expense, net in operating expenses allocable to us (d)		2,273			2,274			6,820			6,852
Loss on sale of assets in operating costs and expenses (c)		(35	)		(6	)		(67	)		6

Total segment gross operating margin	$	68,534		$	107,174		$	301,455		$	200,362


(a) These amounts are comprised of both third-party and related party totals as shown on our Statements of Consolidated Operations and Comprehensive Income.
(b) This amount is taken directly from our Statements of Consolidated Operations and Comprehensive Income.
(c) This amount is taken directly from the operating activities section of our Statements of Consolidated Cash Flows.
(d) This non-cash amount represents the value of the operating leases contributed EPCO to us for which EPCO has retained the cash payment obligation (the “retained leases”). This amount is taken from the operating activities section (“Operating lease expense paid by EPCO” line item) of our Statements of Consolidated Cash Flows.

The following table reconciles GAAP operating income as shown on our Statements of Consolidated Operations and Comprehensive Income to total segment gross operating margin for the periods indicated:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
Operating income	$	30,775		$	68,343		$	182,492		$	107,141
Adjustments to reconcile operating income
to total gross operating margin:
Depreciation and amortization in operating costs and expenses		28,259			24,292			83,761			58,491
Retained lease expense, net in operating costs and expenses		2,273			2,274			6,820			6,852
Loss (gain) on sale of assets in operating costs and expenses		(35	)		(6	)		(67	)		6
Selling, general and administrative costs		7,262			12,271			28,449			27,872

Total segment gross operating margin	$	68,534		$	107,174		$	301,455		$	200,362

Information by business segment, together with reconciliations to the consolidated totals, is presented in the following table:

	Operating Segments													Adjs.
	Fractionation		Pipelines		Processing			Octane Enhancement			Other			and Elims.			Consol. Totals
Revenues from third parties:
Three months ended September 30, 2003	$	182,559	$	94,833	$	766,039					$	613					$	1,044,044
Three months ended September 30, 2002		173,304		121,717		499,251						370						794,642
Nine months ended September 30, 2003		582,582		477,109		2,422,526						1,917						3,484,134
Nine months ended September 30, 2002		440,162		296,929		1,302,431						1,178						2,040,700

Revenues from related parties:
Three months ended September 30, 2003		744		115,524		74,468												190,736
Three months ended September 30, 2002		6,477		52,586		89,577						31						148,671
Nine months ended September 30, 2003		2,017		189,578		251,296												442,891
Nine months ended September 30, 2002		18,386		115,044		217,372						122						350,924

Intersegment and intrasegment revenues:
Three months ended September 30, 2003		52,570		32,915		225,136						101		$	(310,722	)
Three months ended September 30, 2002		59,737		27,469		123,049						100			(210,355	)
Nine months ended September 30, 2003		194,669		136,602		563,397						303			(894,971	)
Nine months ended September 30, 2002		149,237		77,557		390,278						302			(617,374	)

Total revenues:
Three months ended September 30, 2003		235,873		243,272		1,065,643						714			(310,722	)		1,234,780
Three months ended September 30, 2002		239,518		201,772		711,877						501			(210,355	)		943,313
Nine months ended September 30, 2003		779,268		803,289		3,237,219						2,220			(894,971	)		3,927,025
Nine months ended September 30, 2002		607,785		489,530		1,910,081						1,602			(617,374	)		2,391,624

Equity in income (loss) of unconsolidated
affiliates:
Three months ended September 30, 2003		918		2,237				$	(21,195	)								(18,040	)
Three months ended September 30, 2002		2,102		2,705					1,156									5,963
Nine months ended September 30, 2003		1,781		9,436					(27,864	)								(16,647	)
Nine months ended September 30, 2002		5,714		9,506					7,038									22,258

Gross operating margin by individual
business segment and in total:
Three months ended September 30, 2003		30,617		66,589		(6,884	)		(21,195	)		(593	)					68,534
Three months ended September 30, 2002		34,585		63,887		8,417			1,155			(870	)					107,174
Nine months ended September 30, 2003		95,535		210,490		25,757			(27,864	)		(2,463	)					301,455
Nine months ended September 30, 2002		92,815		128,745		(26,141	)		7,038			(2,095	)					200,362

Segment assets:
At September 30, 2003		438,751		2,148,423		164,233			39,105			24,359			105,770			2,920,641
At December 31, 2002		444,016		2,166,524		134,237						16,825			49,237			2,810,839

Investments in and advances
to unconsolidated affiliates:
At September 30, 2003		89,774		212,098		33,000												334,872
At December 31, 2002		95,467		213,632		33,000			54,894									396,993

Intangible Assets:
At September 30, 2003		69,182		7,720		189,973												266,875
At December 31, 2002		71,069		7,895		198,697												277,661

Goodwill:
At September 30, 2003 and
December 31, 2002		81,547																81,547

13. UNIT OPTION PLAN ACCOUNTING

During 1998, EPCO adopted its 1998 Long-Term Incentive Plan (the “1998 Plan”). Under the 1998 Plan, non-qualified incentive options to purchase a fixed number of our Limited Partner’s Common Units (the “Units”) may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. The exercise price per Unit, vesting and expiration terms, and rights to receive distributions on Units granted are determined by EPCO for each grant. EPCO purchases the Units under the 1998 Plan at fair value either in the open market or from our Limited Partner (in the form of newly-issued common units or reissued treasury units). In general, our responsibility for reimbursing EPCO for the cash outlay it incurs when these options are exercised is as follows:

•

We pay EPCO for the costs attributable to equity-based awards granted to operations personnel it employs on our behalf. Our payment to EPCO is in the form of a special distribution made through our Limited Partner.

•

We pay EPCO for our share of the costs attributable to equity-based awards granted to certain of its employees in administrative and management positions that were active at the time of our initial public offering in July 1998 who manage our business and affairs. These costs are reimbursed through the administrative service fees we pay EPCO. EPCO is responsible for the actual costs of such awards when these options are exercised. To the extent that EPCO’s total administrative costs (including the cost of such equity-based awards) exceed the annual administrative service fees we pay to them, such excess costs will result in a charge against our earnings as a non-cash related party expense with a corresponding credit to Partners’ Equity recorded as a contribution.

Accounting principles require us to illustrate the pro forma effect on our net income as if the fair value-based method of accounting (based on SFAS No. 123, “Accounting for Stock Based Compensation”) had been applied to the 1998 Plan. The following table shows these pro forma effects for the periods indicated:

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
Historical net income (loss)	$	(3,008	)	$	35,319		$	71,918		$	40,615
Additional Unit option-based compensation
expense estimated using the fair
value-based method		(171	)		(273	)		(514	)		(820	)

Pro forma net income (loss)	$	(3,179	)	$	35,046		$	71,404		$	39,795

14. SUBSEQUENT EVENTS

In October 2003, we refinanced our 364-Day Revolving Credit facility. The credit line available under this facility now expires in October 2004. In accordance with terms of the new credit agreement, we have the option to convert any revolving credit balance outstanding at maturity to a one-year term loan (due October 2005). In connection with this refinancing, certain financial ratio covenants of our 364-Day and Multi-Year Revolving Credit facilities were amended to increase our financial flexibility.

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.

For the three and nine months ended September 30, 2003 and 2002.

Enterprise Products Partners L.P. is a publicly-traded limited partnership (NYSE, symbol “EPD”) that conducts substantially all of its business through its 98.9899% owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”), the Operating Partnership’s subsidiaries, and a number of investments with industry partners. Since the Operating Partnership owns substantially all of Enterprise Products Partners L.P.‘s consolidated assets and conducts substantially all of its business and operations, the information set forth herein constitutes combined information for the two registrants. Unless the context requires otherwise, references to “we”, “us”, “our” or the “Company” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P., which includes Enterprise Products Operating L.P. and its subsidiaries.

The following discussion and analysis should be read in conjunction with the unaudited consolidated financial statements and notes thereto of the Company and Operating Partnership included under Part I of this quarterly report on Form 10-Q. Additionally, certain abbreviated entity names and other capitalized and industry terms are defined within the glossary of this report.

Our results of operations

We have five reportable business (or operating) segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. Pipelines consists of NGL, petrochemical and natural gas pipeline systems, storage and import/export terminal services. Fractionation primarily includes NGL fractionation, isomerization and propylene fractionation. Processing includes our natural gas processing business and related NGL marketing activities. Octane Enhancement represents our investment in a facility that produces motor gasoline additives to enhance octane (currently producing MTBE). The Other business segment consists of fee-based marketing services and various operational support activities.

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP measure most directly comparable to total segment gross operating margin is operating income.

We define total segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the payment obligation; (3) gains and losses on the sale of assets; and (4) selling, general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions. In accordance with GAAP, intercompany accounts and transactions are eliminated in consolidation. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers, which may be a supplier of raw materials or a consumer of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations. For additional information regarding our business segments, please read footnote 12 of our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

The following table summarizes our consolidated revenues, costs and expenses, equity in income (loss) of unconsolidated affiliates and operating income for the periods indicated (dollars in thousands):

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2003			2002		2003			2002
Revenues	$	1,234,780		$	943,313	$	3,927,025		$	2,391,624
Operating costs and expenses		1,178,703			868,662		3,699,437			2,278,869
Selling, general and administrative costs		7,415			12,289		28,939			27,991
Equity in income (loss) of unconsolidated affiliates		(18,040	)		5,963		(16,647	)		22,258
Operating income		30,622			68,325		182,002			107,022

The following table reconciles consolidated operating income to our measurement of total segment gross operating margin for the periods indicated (dollars in thousands):

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
Operating income	$	30,622		$	68,325		$	182,002		$	107,022
Adjustments to reconcile operating income
to total gross operating margin:
Depreciation and amortization in operating costs and expenses		28,259			24,292			83,761			58,491
Retained lease expense, net in operating costs and expenses		2,273			2,274			6,820			6,852
Loss (gain) on sale of assets in operating costs and expenses		(35	)		(6	)		(67	)		6
Selling, general and administrative costs		7,415			12,289			28,939			27,991

Total segment gross operating margin	$	68,534		$	107,174		$	301,455		$	200,362

EPCO subleases to us certain equipment located at our Mont Belvieu facility and 100 railroad tankcars for $1 dollar per year. These subleases (the “retained lease expense” in the previous table) are part of the EPCO Agreement we executed with EPCO at our formation in 1998. EPCO holds these items pursuant to operating leases for which it has retained the corresponding cash lease payment obligation. Operating costs and expenses (as shown in the Statements of Consolidated Operations and Comprehensive Income) treat the lease payments being made by EPCO as a non-cash related party operating expense, with the offset to Partners’ Equity on the Consolidated Balance Sheets recorded as a general contribution to the Company. Apart from the partnership interests we granted to EPCO at our formation, EPCO does not receive any additional ownership rights as a result of its contribution to us of the retained leases. In addition, EPCO has assigned to us the purchase options associated with these leases. For additional information regarding the EPCO Agreement and the retained leases, please read “Related party transactions – Relationship with EPCO and its affiliates” on page 61 and “Our liquidity and capital resources – Capital spending forecasts” on page 59 of this quarterly report.

Our gross operating margin amounts by segment were as follows for the periods indicated (dollars in thousands):

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2003			2002			2003			2002
Gross operating margin by segment:
Pipelines	$	66,589		$	63,887		$	210,490		$	128,745
Fractionation		30,617			34,585			95,535			92,815
Processing		(6,884	)		8,417			25,757			(26,141	)
Octane enhancement		(21,195	)		1,155			(27,864	)		7,038
Other		(593	)		(870	)		(2,463	)		(2,095	)

Total segment gross operating margin	$	68,534		$	107,174		$	301,455		$	200,362

Our significant pipeline throughput, plant production and processing volumetric data were as follows for the periods indicated (on a net basis, taking into account our ownership interests):

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2003		2002		2003		2002
MBPD, net
NGL and petrochemical pipelines		1,400		1,353		1,366		1,375
NGL fractionation		233		247		223		233
Propylene fractionation		54		55		57		55
Isomerization		77		88		80		82
Equity NGL production		57		78		53		78
Octane enhancement		4		5		4		5

BBtus per day, net
Natural gas pipelines		1,058		1,250		1,042		1,254

Equivalent MBPD, net
NGL, petrochemical and natural gas pipelines		1,678		1,682		1,640		1,705

The following table illustrates selected average quarterly industry index prices for natural gas, crude oil, selected NGL and petrochemical products and indicative gas processing gross spreads since the beginning of 2002:

	Natural Gas, $/MMBtu	Crude Oil, $/barrel	Ethane, $/gallon	Propane, $/gallon	Normal Butane, $/gallon	Isobutane, $/gallon	Natural Gasoline, $/gallon	Polymer Grade Propylene, $/pound	Refinery Grade Propylene, $/pound	Indicative Gas Processing Gross Spread, $/gallon
	(a)	(b)	(a)	(a)	(a)	(a)	(a)	(a)	(a)	(c)
2002
1st Quarter	$ 2.34	$ 21.41	$ 0.22	$ 0.30	$ 0.38	$ 0.44	$ 0.47	$ 0.16	$ 0.12	$ 0.12
2nd Quarter	$ 3.38	$ 26.26	$ 0.26	$ 0.40	$ 0.48	$ 0.51	$ 0.58	$ 0.20	$ 0.17	$ 0.10
3rd Quarter	$ 3.16	$ 28.30	$ 0.26	$ 0.42	$ 0.52	$ 0.58	$ 0.61	$ 0.21	$ 0.16	$ 0.14
4th Quarter	$ 3.99	$ 28.33	$ 0.31	$ 0.49	$ 0.60	$ 0.63	$ 0.66	$ 0.20	$ 0.15	$ 0.13

Average	$ 3.22	$ 26.08	$ 0.26	$ 0.40	$ 0.50	$ 0.54	$ 0.58	$ 0.20	$ 0.15	$ 0.12

2003
1st Quarter	$ 6.58	$ 34.12	$ 0.43	$ 0.65	$ 0.76	$ 0.80	$ 0.85	$ 0.24	$ 0.21	$ 0.05
2nd Quarter	$ 5.40	$ 29.04	$ 0.39	$ 0.53	$ 0.58	$ 0.62	$ 0.65	$ 0.25	$ 0.19	$ 0.04
3rd Quarter	$ 4.97	$ 30.21	$ 0.37	$ 0.56	$ 0.67	$ 0.68	$ 0.73	$ 0.21	$ 0.15	$ 0.10

Average	$ 5.65	$ 31.12	$ 0.40	$ 0.58	$ 0.67	$ 0.70	$ 0.74	$ 0.23	$ 0.18	$ 0.06


(a) Natural gas, NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including OPIS and CMAI. Natural gas price is representative of Henry-Hub I-Ferc. NGL prices are representative of Mont Belvieu Non-TET pricing. Refinery grade propylene represents an average of CMAI spot prices. Polymer-grade propylene represents average CMAI contract pricing.
(b) Crude Oil price is representative of an index price for West Texas Intermediate.
(c) The Indicative Gas Processing Gross Spread is a relative measure used by the NGL industry as an indicator of the gross economic benefit derived from extracting NGLs from natural gas production on the U.S. Gulf Coast. Specifically, it is the amount that the economic value of a composite gallon of NGLs exceeds the value of the equivalent amount of energy of natural gas based on NGL and natural gas prices on the U.S. Gulf Coast. It is assumed that a gallon of NGLs is comprised of 33% ethane, 32% propane, 11% normal butane, 8% isobutane and 16% natural gasoline. The value of a composite gallon of NGLs is determined by multiplying these component percentages by industry index prices listed in the table above. The value of the equivalent amount of energy of natural gas to one gallon of NGLs is 8.9% of the price of a MMBtu of natural gas. The Indicative Gas Processing Gross Spread does not consider the operating and fuel costs incurred by a natural gas processing plant to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs and natural gas to market.

Three months ended September 30, 2003 compared to three months ended September 30, 2002

Revenues, costs and expenses and operating income and total segment gross operating margin.

Revenues for the three months ended September 30, 2003 increased $291.5 million over those recorded during the same period in 2002. Costs and expenses for the third quarter of 2003 increased $305.2 million over those of the third quarter of 2002. The increase in revenues and costs and expenses is primarily due to higher NGL and natural gas prices quarter-to-quarter, both of which offset the effects of lower volumes at many of our pipelines and facilities.

In general, higher selling prices result in increased revenues from our various marketing activities; however, these same higher prices also increase our cost of sales within these activities as feedstock and other purchase prices rise. In addition, higher natural gas prices during the third quarter of 2003 increased energy-related costs for many of our businesses versus the same period in 2002.

When compared to the third quarter of 2002, volumes at many of our downstream pipelines and facilities were lower due to a combination of (i) decreased demand for NGLs by the petrochemical industry and (ii) lower NGL extraction rates at domestic gas processing facilities. The most significant determinant of the relative economic value of NGLs is demand by the petrochemical industry for use in manufacturing plastics and chemicals. When compared to 2002, this industry has been operating at lower utilization rates during 2003 primarily due to a recession in the domestic manufacturing sector. As a result of the higher relative cost of NGLs to other crude-based alternatives, the petrochemical industry has been utilizing less expensive feedstocks such as naphtha for their operations in place of NGLs such as ethane. The resulting weak demand for NGLs by the petrochemical industry has limited the ability of NGL producers to increase product prices, which in turn has resulted in decreased NGL extraction rates during the 2003 period.

Equity earnings from unconsolidated affiliates decreased $24.0 million quarter-to-quarter primarily due to a $22.5 million non-cash impairment charge we recorded related to our BEF investment. The deteriorating business environment and outlook prompted BEF to review the carrying value of its long-lived assets for impairment during September 2003.

As a result of items noted in the previous paragraphs, operating income for the third quarter of 2003 decreased $37.7 million from that of the third quarter of 2002. Total segment gross operating margin decreased $38.6 million quarter-to-quarter due to the same general reasons underlying the decrease in operating income. Operating income includes costs such as depreciation and amortization and selling, general and administrative expenses that are excluded from the non-GAAP financial measure of total segment gross operating margin.

The following information highlights the significant quarter-to-quarter variances in gross operating margin by business segment:

Pipelines. Gross operating margin from our Pipelines segment was $66.6 million for the third quarter of 2003 compared to $63.9 million for the third quarter of 2002. On an energy-equivalent basis where 3.8 MMBtus of natural gas throughput are equivalent to one barrel of NGL throughput, net pipeline throughput was 1,678 MBPD during the third quarter of 2003 versus 1,682 MBPD during the same period in 2002.

Gross operating margin from the Mid-America and Seminole pipeline systems increased $2.6 million to $32.7 million for the third quarter of 2003 on aggregate net volume of 735 MBPD. Gross operating margin from these pipelines for the two months that we owned them during the third quarter of 2002 was $30.1 million on aggregate net volumes of 868 MBPD. Throughput and gross operating margin for these systems were lower quarter-to-quarter due to decreased demand for NGLs and weaker gas processing economics, which caused natural gas processing plants in the Rocky Mountains to reduce the amount of ethane extracted. This resulted in lower transportation volumes on both the Mid-America and Seminole pipeline systems.

Gross operating margin from our Houston Ship Channel NGL import facility (and related HSC pipeline system) increased $4.7 million quarter-to-quarter primarily due to a 141 MBPD increase in aggregate volumes. NGL import activity increased as a result of higher domestic prices for NGLs relative to international prices for such

products. Our recently acquired Port Neches Pipeline added $0.7 million in gross operating margin on volumes of 25 MBPD.

Gross operating margin from our other Gulf Coast region pipeline and storage assets decreased $5.3 million quarter-to-quarter. Our Louisiana Pipeline System posted a decrease in gross operating margin of $1.6 million for the third quarter of 2003 primarily due to lower equity NGL throughput rates. Gross operating margin from Acadian Gas for the third quarter of 2003 decreased $1.0 million from the same period in 2002 primarily due to lower natural gas throughput. Gross operating margin from our NGL and petrochemical storage operations declined $2.1 million quarter-to-quarter due to lower revenues and higher maintenance and energy-related expenses.

Fractionation. Gross operating margin from our Fractionation segment was $30.6 million for the third quarter of 2003 compared to $34.6 million for the third quarter of 2002. Gross operating margin from NGL fractionation was $5.6 million for both periods. Net NGL fractionation volumes decreased to 233 MBPD during the third quarter of 2003 from 247 MBPD during the same period in 2002. An increase in processing volumes and fees at our Mont Belvieu and Norco NGL fractionators were offset by lower volumes at our other facilities and higher overall energy-related expenses. The decrease in fractionation volumes is primarily due to lower NGL extraction rates at gas processing facilities.

Gross operating margin from propylene fractionation decreased $3.3 million quarter-to-quarter primarily due to weak demand for polymer-grade propylene and higher operating costs, which was partially offset by increased sales of refinery-grade propylene. Net propylene fractionation volumes were 54 MBPD during the third quarter of 2003 versus 55 MBPD during the third quarter of 2002.

Gross operating margin from isomerization increased $0.8 million quarter-to-quarter. Isomerization volumes decreased to 77 MBPD during the third quarter of 2003 from 88 MBPD during the third quarter of 2002. The increase in gross operating margin from isomerization is generally attributable to higher isomerization fees, which were partially offset by the effect of lower volumes and higher energy-related costs. Certain components of our isomerization fees are indexed to the price of natural gas, which was significantly higher during the third quarter of 2003 relative to the same period in 2002.

Processing. Gross operating margin from our Processing segment was a loss of $6.9 million for the third quarter of 2003 compared to income of $8.4 million for the third quarter of 2002. Gross operating margin from NGL marketing in the third quarter of 2003 decreased by approximately $8.0 million from the same period in 2002. This decrease was primarily due to lower sales margins.

Gross operating margin from natural gas processing decreased $7.3 million quarter-to-quarter primarily due to weaker gas processing economics. Equity NGL production at our gas processing plants was 57 MBPD for the third quarter of 2003 compared to 78 MBPD during the third quarter of 2002. The decrease in equity NGL production quarter-to-quarter is largely attributable to reduced demand for NGLs by industry and higher natural gas prices relative to NGL prices, the combination of which suppressed NGL extraction rates by gas processors.

Beginning in August 2003, approximately 200 million cubic feet per day of natural gas production volume flowing into our gas plants for processing (or approximately 10% of the total amount of gas processing by us) that had been historically processed under keepwhole arrangements was converted to fee-based arrangements. Unlike a traditional keepwhole contract, we will receive a tolling fee from the producer based on the volume of gas we process. NGL volumes under these fee-based arrangements continue to utilize our downstream pipeline, storage and NGL fractionation services.

We process approximately 2.1 Bcf of natural gas per day. For the remainder of 2003 and for 2004, we estimate that approximately 49% of this gas will be processed under the margin band agreement with Shell ( for additional information regarding this agreement, please read “Related party transactions – Relationship with Shell” beginning on page 61 of this quarterly report); approximately 40% will be processed under percent-of-liquids arrangements; 10% under fee-based arrangements and 1% under legacy keepwhole arrangements.

Octane enhancement. Our equity in earnings from BEF was a loss of $21.2 million for the third quarter of 2003, which includes a non-cash impairment charge of $22.5 million. This compares to equity income of $1.2 million for the third quarter of 2002.

BEF’s assets were written down to fair value, which was determined by independent appraisers using present value techniques. The impaired assets principally represent the plant facility and other assets associated with MTBE production. The fair value analysis incorporates future courses of action being taken (or contemplated to be taken) by BEF management, including the production of iso-octane and alkylate. If the underlying assumptions in the fair value analysis change resulting in expected future cash flows being less than the new carrying value of the facility, additional impairment charges may result in the future.

BEF is currently in the process of preparing detailed engineering plans to convert the facility to iso-octane production. The facility will continue to produce MTBE as market conditions warrant and will be capable of producing either MTBE or iso-octane once the plant modifications are complete. Depending on the outcome of various factors (including pending federal legislation) the facility may be further modified in the future to produce alkylate.

At the end of September 2003, we acquired an additional 33.33% partnership interest in BEF. Due to this acquisition, BEF became a majority-owned consolidated subsidiary of ours on September 30, 2003. Historically, BEF was accounted for as an equity-method unconsolidated affiliate. Its results will continue to be reported under our Octane Enhancement segment.

Selling, general and administrative costs. These expenses were $7.4 million for the third quarter of 2003 versus $12.3 million for the same period in 2002. The 2002 period included approximately $4.0 million we paid to Williams for transition services associated with our acquisition of Mid-America and Seminole. These payments ceased in February 2003 when we began operating these two systems.

Interest expense. Interest expense increased to $32.6 million for the third quarter of 2003 from $30.7 million during the same period in 2002. Our average outstanding debt decreased to $1.9 billion during the third quarter of 2003 from $2.5 billion during the third quarter of 2002. The increase in expense is generally attributable to higher fixed-rate interest payments during the 2003 period. At September 30, 2003, approximately 92% of our debt is at fixed-interest rates compared to 36% at September 30, 2002. For additional information regarding our debt, please read “Our liquidity and capital resources – Our debt obligations” beginning on page 57 of this quarterly report.

Nine months ended September 30, 2003 compared to nine months ended September 30, 2002

Revenues, costs and expenses, operating income and total segment gross operating margin.

Revenues for the nine months ended September 30, 2003 increased $1.5 billion over those recorded during the same period in 2002. Year-to-date costs and expenses for 2003 increased $1.4 billion over those of the first nine months of 2002. As with the quarter-to-quarter variances noted previously, the increase in year-to-date revenues

and costs and expenses between the two nine month periods is primarily due to higher prices and acquisitions, both of which offset the effects of lower volumes at many of our pipelines and facilities. In addition, costs and expenses for the nine months ended September 30, 2002 includes a $52.3 million loss related to commodity hedging activities, which was not repeated during the 2003 period. Equity earnings from unconsolidated affiliates decreased $38.9 million period-to-period primarily due to an impairment charge and operating losses incurred by BEF.

As a result of the items noted in the previous paragraph, operating income for the first nine months of 2003 increased $75.0 million over that of the first nine months of 2002. Total segment gross operating margin increased $101.1 million period-to-period due to the same general reasons underlying the increase in operating income. On a period-to-period basis, depreciation and amortization charges increased $25.3 million and selling, general and administrative costs increased $1.0 million primarily due to acquisitions and other business expansion activities.

The following information highlights the significant variances in gross operating margin by business segment between the nine months ended September 30, 2003 and the same period in 2002:

Pipelines. Gross operating margin from our Pipelines segment was $210.5 million for the first nine months of 2003 compared to $128.8 million for the same period during 2002. On an energy-equivalent basis, net pipeline throughput was 1,640 MBPD during the 2003 period versus 1,705 MBPD during the 2002 period. The increase in gross operating margin is primarily due to our acquisition of Mid-America and Seminole. These two systems earned gross operating margin of $120.1 million during the first nine months of 2003 on aggregate net volumes of 769 MBPD. Since we acquired interests in these systems at the end of July 2002, the 2002 period includes $30.1 million we recorded from these systems during August and September 2002. When compared to their historical operating rates, net pipeline transportation volumes on the Mid-America and Seminole systems for the first nine months of 2003 were lower than those reported for the first nine months of 2002 primarily due to a decreased demand for NGLs by industry and lower NGL extraction rates at regional gas processing facilities.

Excluding the contributions of Mid-America and Seminole, gross operating margin for the Pipelines segment was $90.4 million for the first nine months of 2003 versus $98.7 million for the same period in 2002. On an energy-equivalent basis (excluding Mid-America and Seminole), net pipeline throughput volumes increased to 871 MBPD during the 2003 period from 837 MBPD during the 2002 period. An increase in gross operating margins from our Houston Ship Channel NGL import terminal (and related HSC pipeline), the Lou-Tex NGL and Lou-Tex Propylene pipelines plus the addition of gross operating margin from our recently acquired Port Neches Pipeline offset a net decline in our other Gulf Coast area pipeline operations (due in part to lower NGL extraction rates at regional gas processing facilities and demand for NGLs by industry). The 34 MBPD increase in net volumes was primarily due to higher throughput rates at our NGL import terminal (and related HSC pipeline). In addition, 2003 gross operating margin from our NGL and petrochemical storage operations was $7.0 million lower period-to-period primarily due to higher energy and maintenance-related costs and net charges associated with the measurement of liquids volumes held in storage.

Fractionation. Gross operating margin from our Fractionation segment was $95.5 million for the first nine months of 2003 compared to $92.8 million for the same period in 2002. Gross operating margin from NGL fractionation improved $6.4 million period-to-period. Net NGL fractionation volumes decreased to 223 MBPD during the first nine months of 2003 from 233 MBPD during the same period in 2002. The increase in NGL fractionation gross operating margin is primarily due to (i) mixed NGL measurement gains we recognized during the second quarter of 2003 at our Mont Belvieu facility and (ii) higher in-kind fees during the 2003 period at Norco attributable to the general increase in NGL prices, both of which more than offset a decline in gross operating margin from our other NGL fractionation facilities generally due to lower volumes and higher energy-related costs. The decrease in NGL fractionation volumes period-to-period is primarily due to lower NGL extraction rates at gas processing facilities and reduced demand for NGLs by industry.

Gross operating margin from propylene fractionation declined $9.8 million period-to-period primarily due to lower petrochemical marketing margins resulting from higher feedstock and energy-related costs. Net propylene fractionation volumes were 57 MBPD for the first nine months of 2003 compared to 55 MBPD for the same period during 2002.

Gross operating margin from isomerization increased $6.4 million period-to-period. Isomerization volumes were 80 MBPD during the 2003 period compared to 82 MBPD during the 2002 period. The increase in gross operating margin from isomerization is generally attributable to higher isomerization fees and by-product revenues, which were partially offset by higher energy-related operating costs.

Processing. Gross operating margin from our Processing segment was income of $25.8 million for the first nine months of 2003 compared to a loss of $26.1 million for the same period in 2002. The first nine months of 2002 includes $52.3 million in commodity hedging losses, the underlying strategies of which were discontinued in 2002. Our commodity hedging results for the first nine months of 2003 were a loss of $0.1 million.

Equity NGL production at our gas processing plants during the 2003 period averaged 53 MBPD compared to 78 MBPD during the 2002 period. The decrease in equity NGL production period-to-period is largely attributable to reduced demand for NGLs by industry and higher natural gas prices relative to NGL prices, which caused most natural gas processors to minimize the amount of NGLs extracted at their facilities. In order to meet the natural gas processing needs of Shell (our largest natural gas processing customer) in this challenging business environment, we renegotiated certain aspects of the 20-year Shell natural gas processing agreement during the first quarter of 2003. For a general discussion of this amendment, please read “Related party transactions – Relationship with Shell” beginning on page 61 of this quarterly report.

In addition, we converted contracts covering approximately 10% of the total amount of natural gas processed by us from traditional keepwhole contracts to fee-based arrangements during the third quarter of 2003. For a general discussion of these conversions, please read “Our results of operations – Three months ended September 30, 2003 compared to three months ended September 30, 2002 – Processing” on page 50 of this quarterly report.

Octane enhancement. Our equity earnings from BEF were a loss of $27.9 million for the first nine months of 2003 compared to income of $7.0 million for the same period during 2002. Net MTBE production from this facility decreased to 4 MBPD during the 2003 period versus 5 MBPD during the 2002 period. The $34.9 million decrease in equity earnings is primarily due to a $22.5 million impairment charge we recorded during the third quarter of 2003 and increased downtime during 2003 for maintenance and economic reasons and an overall deterioration of MTBE sales margins. For additional information regarding the impairment charge we recorded during the third quarter of 2003, please read “Our results of operations – Three months ended September 30, 2003 compared to three months ended September 30, 2002 – Octane Enhancement” on page 51 of this quarterly report.

Selling, general and administrative costs. These expenses were $28.9 million for the first nine months of 2003 compared to $28.0 million for the same period during 2002. The increase is primarily due to additional staff and resources required to support expanded business activities resulting from acquisitions and other business development.

Interest expense. Interest expense increased to $107.8 million for the first nine months of 2003 from $68.2 million for the same period in 2002. The increase is primarily due to additional debt we incurred as a result of business acquisitions. Our weighted-average debt principal outstanding was $2.0 billion for the 2003 period compared to $1.6 billion for the 2002 period.

Interest expense for 2003 includes $11.3 million of loan cost amortization related to the 364-Day Term Loan, which was fully repaid in February 2003. For additional information regarding our debt obligations and changes therein since December 31, 2002, please read “Our liquidity and capital resources – Our debt obligations” beginning on page 57 of this quarterly report.

Outlook for remainder of 2003

Our outlook for the remainder of 2003 is largely dependent on demand for NGLs by the petrochemical industry and an overall recovery in the domestic manufacturing sector; improved natural gas processing economics in the Rocky Mountains and new natural gas production from deepwater Gulf of Mexico developments. In general, business conditions were much better at the end of the third quarter than at its beginning. We are encouraged by the continued improvement in business conditions that we have seen early in the fourth quarter of 2003.

According to industry publications, petrochemical demand for various NGL products continues to increase. Ethane demand by the petrochemical industry appears to have bottomed out in June and July at an average of 574 MBPD, which was 23% below the five-year average of 750 MBPD. Average ethane demand climbed to approximately 700 MBPD from August through October. This increase in NGL demand has resulted in a strengthening of natural gas processing economics, which should result in higher NGL extraction rates at domestic gas processing facilities. The increase in NGL extraction rates should provide additional volumes for our pipelines and other downstream facilities during the fourth quarter of 2003 when compared to the second and third quarters of 2003.

On October 9, 2003, we published on Form 8-K our forecasts for net income and earnings per Unit for the fourth quarter of 2003 and full-year 2003 based on our expectations at that time. Our expectation for net income for the fourth quarter of 2003 was in the range of $40 million to $50 million, or approximately $0.16 to $0.20 per Unit (on a fully diluted basis).

Our liquidity and capital resources

The following represents a combined discussion of our liquidity and capital resources and those of our Operating Partnership. Within this section, references to partnership equity pertains to limited partner interests issued by us, whereas references to debt pertains to those obligations entered into by our Operating Partnership or its subsidiaries.

General

Our primary cash requirements, in addition to normal operating expenses and debt service, are for capital expenditures (both sustaining and expansion-related), business acquisitions and distributions to our partners. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows. Capital expenditures for long-term needs resulting from internal growth projects and business acquisitions are expected to be funded by a variety of sources including (either separately or in combination) cash flows from operating activities, borrowings under commercial bank credit facilities, the issuance of additional partnership equity and public or private placement debt. We expect to fund cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.

Operating cash flows primarily reflect the effects of net income adjusted for depreciation and amortization, equity income and cash distributions from unconsolidated affiliates, fluctuations in the fair value of financial instruments and changes in operating accounts. The net effect of changes in operating accounts is generally the result of timing of sales and purchases near the end of each period. Cash flow from operations is primarily based on earnings from our business activities. As a result, these cash flows are exposed to certain risks. The products that we process, sell or transport are principally used as feedstocks in petrochemical manufacturing, in the production of motor gasoline and as fuel for residential, agricultural and commercial heating. Reduced demand for our products or services by industrial customers, whether because of general economic conditions, reduced demand for the end products made with our products, increased competition from petroleum-based products due to pricing differences or other reasons, could have a negative impact on our earnings and thus the availability of cash from operating activities. Other risks include fluctuations in NGL and energy prices, competitive practices in the midstream energy industry and the impact of operational and systems risks. For a more complete discussion of these and other risk factors pertinent to our business, please read “Cautionary statement regarding forward-looking information and risk factors” on page 66 of this quarterly report.

As noted above, certain of our liquidity and capital resource requirements are fulfilled by borrowings made under debt agreements and/or proceeds from the issuance of additional partnership equity. At September 30, 2003, we had approximately $1.9 billion in principal outstanding under various debt agreements. On that date, total borrowing capacity under our revolving commercial bank credit facilities was $500 million of which $341.1 million of capacity was available. For additional information regarding our debt, please read “– Our debt obligations” beginning on page 57 of this quarterly report.

In February 2001, we filed a universal shelf registration with the SEC covering the issuance of up to $500 million of partnership equity or public debt obligations. In October 2002, we sold 9,800,000 Common Units under

this shelf registration statement which generated $182.5 million of cash to us (including related capital contributions from our General Partner). In January 2003, we sold an additional 14,662,500 Common Units under this shelf registration which generated $258.2 million of cash to us (including related capital contributions from our General Partner). We used the cash generated by these equity offerings to reduce debt outstanding under our 364-Day Term Loan and for working capital purposes. Also, in January and February 2003, we issued Senior Notes C ($350 million principal amount) and Senior Notes D ($500 million principal amount). For information regarding our application of cash obtained through these debt offerings, please read “– Our debt obligations” beginning on page 57 of this quarterly report.

In January 2003, we filed a new $1.5 billion universal shelf registration statement with the SEC covering the issuance of an unallocated amount of partnership equity or public debt obligations (separately or in combination). In June 2003, we sold 11,960,000 Common Units under this shelf registration statement, which generated $261.2 million of cash to us (including related capital contributions from our General Partner). We used the cash generated by this equity offering to reduce debt outstanding under our revolving credit facilities. As a result of meeting certain financial tests, the Subordination Period (as defined within our partnership agreement) ended on August 1, 2003. With the expiration of the Subordination Period, we may prudently issue an unlimited number of Units for general partnership purposes.

In July 2003, we filed a registration statement with the SEC regarding our Distribution Reinvestment Plan (the “Plan”). The Plan provides unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units. The registration statement covers the issuance of up to 5,000,000 Common Units under the Plan. As a result of any future reinvestment proceeds, our General Partner will be required to make cash contributions to us and our Operating Partnership in order to maintain its ownership interests. We expect to use the cash generated from this reinvestment program for general partnership purposes.

Initial reinvestments under the Plan occurred in August 2003 for those Common Unitholders of record and beneficial owners on July 31, 2003 who elected to participate with regards to our August 2003 distribution. We issued 1,268,404 Common Units and received proceeds of approximately $26.0 million (including related capital contributions from our General Partner). EPCO’s reinvestment accounted for approximately $25 million of the $26 million reinvested during August 2003. To support our growth objectives and financial flexibility, EPCO has announced that it expects to reinvest under the Plan approximately $180 million of its cash distributions over the next six fiscal quarters beginning with the fourth quarter of 2003. As a result, we are preparing to increase the number of Common Units that can be issued under the Plan to approximately 15,000,000 Common Units.

If deemed necessary, we believe that additional financing arrangements can be obtained on reasonable terms. Furthermore, we believe that maintenance of our investment grade credit ratings combined with a continued ready access to debt and equity capital at reasonable rates and sufficient trade credit to operate our businesses efficiently provide a solid foundation to meet our long and short-term liquidity and capital resource requirements.

Nine months ended September 30, 2003 compared to nine months ended September 30, 2002

The following discussion highlights significant period-to-period comparisons regarding our consolidated operating, investing and financing activities cash flows:

Operating activities cash flows. Cash flow from operating activities was an inflow of $228.6 million during the first nine months of 2003 compared to an inflow of $170.1 million during the first nine months of 2002. The following table summarizes the major components of operating activities cash flows for first nine months of 2003 and 2002 (dollars in thousands):

	For the Nine Months Ended September 30,
	2003			2002
Net income	$	70,349		$	39,967
Adjustments to reconcile net income to cash flows provided by
(used for) operating activities before changes in operating accounts:
Depreciation and amortization		96,081			62,907
Equity in loss (income) of unconsolidated affiliates		16,647			(22,258	)
Distributions received from unconsolidated affiliates		25,703			40,114
Changes in fair market value of financial instruments		(25	)		12,830
Other		15,870			8,643

Cash flow from operating activities before changes in operating accounts		224,625			142,203
Net effect of changes in operating accounts		3,944			27,906

Operating activities cash flows	$	228,569		$	170,109

As shown in the table above, cash flow before the net effect of changes in operating accounts was an inflow of $224.6 million during the first nine months of 2003 versus $142.2 million during the same period in 2002. We believe that cash flow from operating activities before the net effect of changes in operating accounts is an important measure of our ability to generate core cash flows from our assets and other investments. The $82.4 million increase in this element of our cash flows is primarily due to:

•

earnings from acquired businesses present in the 2003 period but not in the 2002 period (particularly those of Mid-America and Seminole which we acquired in July 2002);

•

the 2002 period including $52.3 million of commodity hedging losses versus $0.9 million of such losses during the 2003 period; offset by,

•

higher interest costs associated with debt we incurred and issued since the first quarter of 2002 to finance acquisitions.

The $33.2 million increase in depreciation and amortization is primarily due to businesses we acquired since the first quarter of 2002. The net effect of changes in operating accounts is generally the result of timing of cash receipts from sales and cash payments for inventory, purchases and other expenses near the end of each period. For additional information regarding changes in operating accounts, please read footnote 10 in our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

Investing activities cash flows. During the first nine months of 2003, we used $153.5 million in cash for investing activities compared to $1.7 billion during the same period in 2002. We used $26.3 million and $1.6 billion for business acquisitions during the first nine months of 2003 and 2002, respectively. The 2002 period reflects our acquisition of indirect interests in Mid-America and Seminole pipelines from Williams and propylene fractionation and NGL and petrochemical storage assets from Diamond-Koch. The 2003 period includes only minor acquisitions, specifically those of the Port Neches Pipeline and additional interests in EPIK and BEF.

Our capital expenditures were $98.0 million during the first nine months of 2003 versus $47.0 million during the first nine months of 2002. The $51.0 million increase in capital expenditures is primarily due to (i) expansions of our Norco NGL fractionator and Neptune gas processing facility and (ii) the rerouting of a 14-mile segment of the Mid-America pipeline in connection with the development of a dam and reservoir by an agency of the federal government. In addition, we made investments in and advances to our unconsolidated affiliates of $29.4 million during the first nine months of 2003 compared to $13.2 million during the first nine months of 2002. This increase is primarily due to funding our share of the expansion projects of our Gulf of Mexico natural gas pipeline investments.

Financing activities cash flows. Our financing activities were a cash outflow of $48.7 million during the first nine months of 2003 versus a cash inflow of $1.4 billion during the first nine months of 2002. During the 2003 period, we made net payments on our debt obligations of $356.8 million primarily due to the use of proceeds from our January and June equity offerings. The 2003 period reflects our issuance of Senior Notes C ($350 million

in principal amount) and Senior Notes D ($500 million in principal amount) and the final repayment of $1.0 billion that was outstanding under our 364-Day Term Loan. The 2002 period primarily reflects borrowings to fund the Mid-America and Seminole acquisitions and those of Diamond-Koch’s propylene fractionation business.

Proceeds from our equity offerings during 2003 totaled $540.2 million, which includes our General Partner’s related $5.4 million contribution to us. Our General Partner also contributed $5.5 million to our Operating Partnership in connection with these offerings. Distributions to our partners and minority interests increased to $223.4 million during the first nine months of 2003 from $150.7 million during the first nine months of 2002. The $72.7 million increase in distributions to partners is primarily due to increases in both the declared quarterly distribution rates and the number of Units eligible for distributions.

Our debt obligations

Our debt obligations consisted of the following at the dates indicated:

	September 30, 2003			December 31, 2002
Borrowings under:
364-Day Term Loan, variable rate, due July 2003				$	1,022,000
364-Day Revolving Credit facility, variable rate,
due November 2004					99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005	$	145,000			225,000
Senior Notes A, 8.25% fixed rate, due March 2005		350,000			350,000
Seminole Notes, 6.67% fixed rate, $15 million due
each December, 2002 through 2005		45,000			45,000
MBFC Loan, 8.70% fixed rate, due March 2010		54,000			54,000
Senior Notes B, 7.50% fixed rate, due February 2011		450,000			450,000
Senior Notes C, 6.375% fixed rate, due February 2013		350,000
Senior Notes D, 6.875% fixed rate, due March 2033		500,000

Total principal amount		1,894,000			2,245,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt		1,591			1,774
Less unamortized discount on:
Senior Notes A		(53	)		(81	)
Senior Notes B		(208	)		(230	)
Senior Notes D		(5,753	)
Less current maturities of debt		(15,000	)		(15,000	)

Long-term debt	$	1,874,577		$	2,231,463

Covenants. We were in compliance with the various covenants of our debt agreements at September 30, 2003 and December 31, 2002. Certain financial ratio covenants of our revolving credit facilities were amended in connection with the refinancing of our 364-Day Revolving Credit facility in October 2003. For additional information regarding our credit facilities, please read “– Revolving credit facilities” beginning on page 58 of this quarterly report.

Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its ownership interests).

New senior notes issued during first quarter of 2003

Repayment of 364-Day Term Loan

In July 2002, our Operating Partnership entered into the $1.2 billion senior unsecured 364-Day Term Loan to fund the acquisition of indirect interests in Mid-America and Seminole. We used $178.5 million of the $182.5 million in proceeds from our October 2002 equity offering to partially repay this loan. We also used $252.8 million of the $258.2 million in proceeds from the January 2003 equity offering, $347.0 million of the $347.7 million in proceeds from our issuance of Senior Notes C and $421.4 million in proceeds from our issuance of Senior Notes D to completely repay the 364-Day Term Loan in February 2003.

Revolving credit facilities

We used $60.0 million in proceeds from the issuance of Senior Notes D in February 2003 to reduce the balance outstanding under our 364-Day Revolving Credit facility. In addition, we applied $261.2 million of the net proceeds from our June 2003 equity offering to reduce the balances then outstanding under our revolving credit facilities, of which $102 million was applied against the 364-Day Revolving Credit facility and $159.2 million against the Multi-Year Revolving Credit facility.

loan (due October 2005). In connection with this refinancing, certain financial ratio covenants of our revolving credit facilities were amended to increase our financial flexibility.

Information regarding variable interest rates paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable-rate debt obligations for the nine months ended September 30, 2003:


364-Day Term Loan (a)	2.59% - 2.88%	2.85%
364-Day Revolving Credit facility	2.44% - 4.25%	2.52%
Multi-Year Revolving Credit facility	1.68% - 4.25%	1.89%


(a) This facility was repaid in February 2003.

Credit ratings

Our current investment grade credit ratings are Baa2 by Moody’s Investor Service and BBB by Standard and Poors. In October 2003, both agencies affirmed their current ratings; however, Standard and Poors revised its outlook from stable to negative. Moody’s Investor Service affirmed that its outlook was stable.

Standard and Poors stated that its negative outlook primarily reflected concerns regarding the sustainability of the current rebound in the NGL industry. Their advisory stated that if our near-term financial results do not meet their current expectations, our rating would be lowered. They are also evaluating what effect, if any, that the purchase of Shell’s interest in our General Partner by an affiliate of EPCO might have on our overall credit quality.

We believe that the maintenance of an investment grade credit rating is important in managing our liquidity and capital resource requirements. We maintain regular communications with these ratings agencies, which independently judge our creditworthiness based on a variety of quantitative and qualitative factors.

Capital spending forecasts

At September 30, 2003, we had $2.6 million in estimated outstanding purchase commitments attributable to capital projects, practically all of which were related to the construction of assets that will be recorded as property, plant and equipment. During the fourth quarter of 2003, we expect capital spending on internal growth projects to approximate $63.9 million, of which $32.8 million is forecasted for various projects within our Pipelines segment; $12.3 million for the expansion of our Norco NGL fractionator (completed in October 2003) and $5.7 million for the expansion of our Neptune gas processing facility (expected completion during fourth quarter of 2003). Our unconsolidated affiliates forecast a combined $16.4 million in capital expenditures for the remainder of 2003, the majority of which relate to Gulf of Mexico natural gas pipeline projects. Our share of these forecasted capital expenditures is approximately $5.4 million.

In October 2003, we purchased from Williams an additional 37.35% interest in Wilprise and 16.67% interest in Tri-States. The total purchase price of these interests was $26.5 million. The initial purchase price excludes approximately $8.3 million in future consideration that is contingent upon throughput volumes on these pipeline systems through 2006. As a result of these acquisitions, our ownership interest in Wilprise is now 74.7% and for Tri-States, 50%.

EPCO subleases to us all of the equipment it holds pursuant to operating leases relating to an isomerization unit, a deisobutanizer tower, a cogeneration unit and approximately 100 railcars for one dollar per year and has assigned to us its purchase option under such leases (the “retained leases”). EPCO remains liable for the lease payments associated with these items. We have notified the original lessor of the isomerization unit of our intent to

exercise the purchase option assigned to us. The purchase price of this equipment is expected to be up to $23.1 million and be payable in 2004.

Pipeline Integrity Management Program

In March 2001, the U.S. Department of Transportation issued safety regulations containing requirements for the development of integrity management programs for oil pipelines (which includes NGL and petrochemical pipelines such as ours) in certain “high consequence areas” (CFR 195.452). High consequence areas include but are not limited to high population areas, environmentally-sensitive locations, and areas containing drinking water supplies. In connection with these regulations, we developed an Integrity Management Program and identified those segments of our liquids pipelines located in such areas by the end of 2002. The regulation stipulates that a pipeline company must assess the condition of its pipeline in such areas and perform any necessary repairs. We are required to evaluate at least 50% of our identified pipeline mileage in such high consequence areas by the end of 2004 with the balance completed before April 2008. After this initial testing is complete, the identified pipeline segments must be reassessed every five years thereafter.

During 2003, we expect to spend approximately $10 million to comply with this new regulation (of which $5 million has been spent during the first nine months). During each of the years 2004 through 2008, these costs are expected to be in the range of $15 million to $19 million. Of these forecasted costs, we expect that approximately 90% will be expensed and the remainder will be recorded as capital expenditures.

Material contractual obligations

There have been no significant changes in our material contractual obligations outside the ordinary course of business since December 31, 2002 except for the following:

•

In February 2003, we completely repaid the $1.0 billion principal balance that was outstanding under the 364-Day Term Loan at December 31, 2002 using proceeds from debt and equity offerings we completed during the first quarter of 2003 (which included the issuance of our Senior Notes C and D discussed below).

•

We issued our $350 million in principal amount Senior Notes C in January 2003. These notes mature in 2013.

•

We issued our $500 million in principal amount Senior Notes D in February 2003. These notes mature in 2033.

•

We used $60 million in proceeds from the issuance of Senior Notes D to repay a portion of indebtedness then outstanding under our 364-Day Revolving Credit facility.

•

We used $261.2 million in proceeds and contributions related to our June 2003 equity offering to reduce indebtedness outstanding under our 364-Day Revolving Credit and Multi-Year Revolving Credit facilities.

The following table summarizes our updated material contractual obligations related to debt at September 30, 2003:

Contractual Obligations			Total			2003			2004 through 2005			2006 through 2007			After 2007
Principal payments to be made
under debt obligations			$	1,894,000		$	15,000		$	525,000		$	0		$	1,354,000

Related party transactions

Relationship with EPCO and Its Affiliates

We have an extensive and ongoing relationship with EPCO and its affiliates. EPCO is controlled by Dan L. Duncan, who is also a director (and Chairman of the Board of Directors) of our General Partner. In addition, three other members of the Board of Directors (O.S. Andras, Randa D. Williams and Richard H. Bachmann) and the remaining executive and other officers of the General Partner are employees of EPCO. The principal business activity of the General Partner is to act as our managing partner. Collectively, EPCO and its affiliates owned 55.4% of our limited partnership interests and 100.0% of our General Partner at September 30, 2003. In September 2003, an affiliate of EPCO purchased Shell’s 30.0% interest in our General Partner.

We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO. We reimburse EPCO for the costs of its employees who perform operating functions for us. In addition, we reimburse EPCO for the costs of certain of its employees who manage our business and affairs.

EPCO is the operator of certain facilities we own or have an equity interest in. We also have entered into an agreement with EPCO to provide trucking services for us pertaining to the loading and transportation of products. Lastly, in the normal course of business, we buy from and sell NGL products to EPCO’s Canadian affiliate.

The following table shows our related party revenues and operating expenses attributable to EPCO for the periods indicated:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2003		2002		2003		2002
Revenues from consolidated operations	$	1,255	$	723	$	2,814	$	3,183
Operating costs and expenses		29,251		24,417		103,396		64,405
Selling, general and administrative expenses		7,212		6,119		20,553		17,907

Relationship with Shell

We have a significant commercial relationship with Shell as a partner, customer and vendor. At September 30, 2003, Shell owned approximately 19.0% of our Common Units. Shell sold its 30.0% interest in our General Partner to an affiliate of EPCO in September 2003.

Shell and its affiliates are the Company’s single largest customer. During the nine months ended September 30, 2003 and 2002, they accounted for 5.7% and 8.6%, respectively, of our consolidated revenues. Our revenues from Shell primarily reflect the sale of NGL and petrochemical products to them and the fees we charge them for pipeline transportation and NGL fractionation services. Our operating costs and expenses with Shell primarily reflect the payment of energy-related expenses related to the Shell natural gas processing agreement and the purchase of NGL products from them.

The most significant contract affecting our natural gas processing business is the 20-year Shell processing agreement, which grants us the right to process Shell’s current and future production within state and federal waters of the Gulf of Mexico. The Shell processing agreement includes a life of lease dedication, which may extend the agreement well beyond its initial 20-year term ending in 2019. This contract was amended effective March 1, 2003. In general, the amended contract includes the following rights and obligations:

•

the exclusive right, but not the obligation in all cases, to process substantially all of Shell's Gulf of Mexico natural gas production; plus

•

the exclusive right, but not the obligation in all cases, to process all natural gas production from leases dedicated by Shell for the life of such leases; plus

•

the right to all title, interest and ownership in the mixed NGL stream extracted by our gas processing plants from Shell’s natural gas production from such leases; with

•

the obligation to re-deliver to Shell the natural gas stream after any mixed NGLs are extracted.

As part of our natural gas processing obligations under this contract, we reimburse Shell for the energy value of (i) the NGLs we extract from the natural gas stream and (ii) the natural gas we remove from the stream and consume as fuel. This energy value is referred to as plant thermal reduction (“PTR”) and is based on the energy content of the natural gas taken out of the stream (measured in Btus). The amended contract contains a mechanism (termed “Consideration Adjustment Outside of Normal Operations” or “CAONO”) to adjust the value of the PTR we reimburse to Shell. The CAONO, in effect, protects us from processing Shell’s natural gas at an economic loss when the value of the NGLs we extract is less than the sum of the cost of the PTR reimbursement, operating costs of the gas processing facility and other costs such as NGL fractionation and pipeline fees.

In general, the CAONO adjustment requires the comparison of our average net gas processing margin to an upper and lower limit (all as defined within the agreement). If our average net processing margin is below the lower limit, the PTR reimbursement payable to Shell is decreased by the product of the absolute value of the difference between our average net processing margin and the specified lower limit multiplied by the volume of NGLs extracted. To the extent our average net processing margin is higher than the upper limit , the PTR reimbursement payable to Shell is increased by the product of the difference between the average net gas processing margin and the specified upper limit multiplied by the volume of NGLs extracted. The underlying purpose of the CAONO mechanism is to provide Shell with relative assurance that its gas will continue to be processed during periods when natural gas prices are high relative to NGL prices (times when we would normally choose not to process a producer’s natural gas stream) while continuing to protect us from processing Shell’s gas at an economic loss.

The following table shows our related party revenues and operating expenses attributable to Shell for the periods indicated:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2003		2002		2003		2002
Revenues from consolidated operations	$	62,806	$	84,750	$	224,242	$	207,108
Operating costs and expenses		131,932		123,172		444,873		362,761

Recent accounting developments

SFAS No. 146, “Accounting for Costs Associated with Exit and Disposal Activities.” We adopted this standard as of January 1, 2003. This statement requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of an entity’s commitment to an exit or disposal plan. Our adoption of this standard has had no material impact on our financial statements.

SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” We adopted this standard as of December 31, 2002. This statement provides alternative methods of transition from a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 in both annual and interim financial statements. We have provided the information required by this statement in footnote 13 of the Notes to Unaudited Consolidated

Financial Statements included under Item 1 of this quarterly report. Apart from this additional footnote disclosure, our adoption of this standard has had no material impact on our financial statements.

Our critical accounting policies

In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect.

In general, there have been no significant changes in our critical accounting policies since December 31, 2002. For a detailed discussion of these policies, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our critical accounting policies” in our annual report on Form 10-K/A for 2002. The following is a condensed discussion of our critical accounting policies and the estimates and assumptions underlying them.

Depreciation methods and estimated useful lives of property, plant and equipment

In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. We use the straight-line method to depreciate our property, plant and equipment. Our estimate of an asset’s useful life is based on a number of assumptions including technological changes that may affect the asset’s usefulness and the manner in which we intend to physically use the asset. If we subsequently change our assumptions regarding these factors, it would result in an increase or decrease in depreciation expense.

At September 30, 2003 and December 31, 2002, the net book value of our property, plant and equipment was $2.9 billion and $2.8 billion, respectively. For additional information regarding our property, plant and

equipment, please read footnote 5 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

Impairment charges and underlying estimated fair values

If we determine that an asset’s undepreciated cost may not be recoverable due to impairment, this would result in a charge against earnings. Long-lived assets with recorded values that are not expected to be recovered through future expected cash flows are written-down to their estimated fair values. An asset is tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the existing asset. Our estimates of such undiscounted cash flows are based on a number of assumptions including anticipated margins and volumes; estimated useful life of the asset or asset group; and salvage values. If we initially determine that an asset’s carrying value is recoverable through such undiscounted estimated cash flows and later revise these assumptions leading to a finding that the opposite is true, we would be required to ascertain the fair value of the facility, which might ultimately result in an impairment charge being recorded.

If the carrying value of an asset exceeds the sum of its undiscounted expected cash flows, an impairment loss equal to the amount the carrying value exceeds the fair value of the asset is recognized. The quoted market price of an asset on an active exchange or similar venue is the best determinant of fair value. However, in many instances, quoted market prices in such markets are not available. In those instances, the estimate of fair value is based on the best information available, including prices for similar assets and the results of using other valuation techniques (including present value techniques).

Since most of our plant and other fixed and intangible assets are not traded in an active market, we generally rely on the use of present value techniques when determining the fair value of such assets for the purpose of impairment testing. These techniques incorporate our best information and assumptions regarding future cash flows, alternative courses of action, probabilities of such courses of action occurring and discount rates. To the extent that any of these underlying assumptions prove incorrect, it may result in additional future impairment charges.

Due to a deteriorating business environment and outlook and the completion of its preliminary engineering studies regarding conversion alternatives, BEF evaluated the carrying value of its long-lived assets for impairment during the third quarter of 2003. This review indicated that the carrying value of BEF’s long-lived assets exceeded their collective fair value, which resulted in a non-cash impairment charge of $67.5 million. Our share of this loss is $22.5 million and is recorded as a component of “Equity in income (loss) of unconsolidated affiliates” in our Statements of Consolidated Operations and Comprehensive Income for the three and nine months ended September 30, 2003. Our historical equity (and in the future, consolidated) earnings from BEF are classified under the Octane Enhancement business segment. For additional information regarding this impairment charge, please read footnote 6 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

Amortization methods and estimated useful lives of qualifying intangible assets

Our recorded intangible assets primarily consist of the estimated value assigned to certain contract-based assets representing the rights we own arising from contractual agreements. A contract-based intangible asset with a finite useful life is amortized over its estimated useful life. Our estimate of useful life is based on a number of factors including the expected useful life of related assets (i.e., fractionation facility, pipeline, etc.) and the effects of obsolescence, demand, competition and other factors. If our underlying assumptions regarding the useful life of an intangible asset change, we then might need to adjust the amortization period of such asset which would increase or decrease amortization expense. Additionally, if we determine that an intangible asset’s unamortized cost may not be recoverable due to impairment, this would result in a charge against earnings.

At September 30, 2003 and December 31, 2002, the carrying value of our intangible asset portfolio was $266.9 million and $277.7 million. For additional information regarding our intangible assets, please read footnote 7 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

Methods we employ to measure the fair value of goodwill

Our goodwill is attributable to the excess of the purchase price over the fair value of assets acquired. Goodwill is not amortized. Instead, goodwill is tested for impairment at a reporting unit level annually, and more frequently, if circumstances warrant. This testing involves calculating the fair value of a reporting unit, which in turn is based on our assumptions regarding the future economic prospects of the reporting unit. If the fair value of the reporting unit (including related goodwill) is less than its book value, a charge to earnings would be required to reduce the carrying value of goodwill to its implied fair value. If our underlying assumptions regarding the future economic prospects of a reporting unit change, this could impact the fair value of the reporting unit and result in a charge to earnings to reduce the carrying value of goodwill.

At September 30, 2003 and December 31, 2002, the carrying value of our goodwill was $81.5 million. For additional information regarding our goodwill, please read footnote 7 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

Our revenue recognition polices

In general, we recognize revenue from our customers when all of the following criteria are met: (i) firm contracts are in place, (ii) delivery has occurred or services have been rendered, (iii) pricing is fixed and determinable and (iv) collectibility is reasonably assured. When contracts settle (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed), we determine if an allowance is necessary and record it accordingly. The revenues that we record are not materially based on estimates. We believe the assumptions underlying any revenue estimates that we use will not prove to be significantly different from actual amounts due to the routine nature of these estimates and the stability of our operations.

Mark-to-market accounting for certain financial instruments

Our earnings are also affected by use of the mark-to-market method of accounting for certain financial instruments. We use short-term, highly liquid financial instruments such as swaps, forwards and other contracts to manage price risks associated with inventories, firm commitments and certain anticipated transactions, primarily within our Processing segment. The use of mark-to-market accounting for financial instruments may cause our non-cash earnings to fluctuate based upon changes in underlying indexes, primarily those related to commodity prices. Fair value for the financial instruments we employ is determined using price data from highly liquid markets such as the NYMEX commodity exchange.

During the first nine months of 2002, we recognized a loss of $52.3 million from our commodity hedging activities. Of this loss, $10.6 million was attributable to the change in fair value of the portfolio between December 31, 2001 and September 30, 2002. The fair value of open positions at September 30, 2002 was a payable of $2.7 million. In March 2002, the effectiveness of our primary commodity hedging strategy deteriorated due to an unexpected rapid increase in natural gas prices; therefore, the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002.

During the first nine months of 2003, we utilized a limited number of commodity financial instruments from which we recorded a loss of $0.9 million. The fair value of open positions at September 30, 2003 was a nominal payable amount. For additional information regarding our financial instruments, please read footnote 11 of the Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

Other items

Conversion of EPCO Subordinated Units to Common Units

On May 1, 2003, 10,704,936 of EPCO’s Subordinated Units converted to Common Units as a result of our satisfying certain financial tests. The remaining 21,409,872 Subordinated Units converted to Common Units on August 1, 2003. These conversions have no impact upon our earnings per unit or distributions since Subordinated

Units are already included in both the basic and fully-diluted earnings per unit calculations and are distribution-bearing.

Conversion of Shell Special Units to Common Units

On August 1, 2003, the last 10,000,000 of Shell’s non-distribution bearing Special Units converted to Common Units. The conversion impacted basic earnings per Unit beginning in the third quarter of 2003. These units were already included in our fully-diluted earnings per Unit computations. Since Common Units are distribution-bearing, our limited partner cash distributions to Shell will increase beginning with the distribution we make in November 2003.

Cautionary statement regarding forward-looking information and risk factors

This quarterly report contains various forward-looking statements and information that are based on our beliefs and those of our General Partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our General Partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our General Partner can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please read our summarized “Risk Factors” below.

Risk Factors

Among the key risk factors that may have a direct impact on our results of operations and financial condition are:

•

A decrease in the difference between NGL product prices and natural gas prices results in lower margins on volumes processed, which would adversely affect our profitability.

•

A reduction in demand for our products by the petrochemical, refining or heating industries could adversely affect our results of operations.

•

A decline in the volume of NGLs delivered to our facilities could adversely affect our results of operations.

•

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

•

Acquisitions and expansions may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing our risks of being unable to effectively integrate these new operations.

•

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by states. If the IRS treats us as a corporation or we become subject to entity-level taxation for state tax purposes, it would substantially reduce distributions to our Unitholders and our ability to make payments on our debt securities.

•

We have leverage that may restrict our future financial and operating flexibility.

•

Terrorist attacks aimed at our facilities could adversely affect our business.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

We are exposed to financial market risks, including changes in commodity prices and interest rates. We may use financial instruments (i.e., futures, forwards, swaps, options, and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions, primarily within our Processing segment. In general, the types of risks we attempt to hedge are those relating to variability of future earnings and cash flows caused by changes in commodity prices and interest rates. As a matter of policy, we do not use financial instruments for speculative (or trading) purposes.

There has been no material change in our commodity financial instruments portfolio since December 31, 2002. During the first quarter of 2003, we settled all interest rate-related financial instruments that were outstanding at December 31, 2002. For additional information regarding our interest-rate related financial instruments, please read “– Interest rate-related financial instruments portfolio” below and footnote 11 of our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

Commodity financial instruments portfolio

At December 31, 2002, the net fair value of this portfolio was a payable of $26 thousand, based entirely upon quoted market prices. At September 30, 2003, the net fair value of this portfolio was a nominal payable amount. We continue to have only a limited number of commodity financial instruments outstanding. The sensitivity of the fair value of our commodity financial instruments portfolio at September 30, 2003 to a hypothetical 10% movement in the underlying quoted market prices is negligible.

At October 29, 2003, the net fair value of this portfolio was a receivable of $0.2 million. The increase is primarily due to an ethane-related transaction expiring by the end of November 2003. If underlying market prices were to increase by 10%, the fair value of the portfolio would decrease to a payable of $0.6 million. If these underlying prices were to decrease by 10%, the fair value of the portfolio would increase to a receivable of $1.0 million.

During the first nine months of 2002, we recognized a loss of $52.3 million from our Processing segment’s commodity hedging activities that was recorded as an operating cost in our Statements of Consolidated Operations and Comprehensive Income. In March 2002, the effectiveness of our primary commodity hedging strategy deteriorated due to an unexpected rapid increase in natural gas prices; therefore, the loss in value of our fixed-price natural gas financial instruments was not offset by increased gas processing margins. We exited the strategy underlying this loss in 2002.

During the first nine months of 2003, we recorded a loss of $0.9 million from our commodity hedging activities, of which $0.8 million is attributable to commodity hedging activities within the Pipelines segment and the remainder to those within the Processing segment.

Interest rate-related financial instruments portfolio

Interest rate swap agreements. At December 31, 2002, we had one interest rate swap outstanding having a notional amount of $54 million and a fair value at that date of $1.6 million. The counterparty elected to exercise its option to terminate this swap as of March 1, 2003 and we received $1.6 million associated with the final settlement of this swap on that date. The early termination of the swap had no impact on our earnings. At September 30, 2003, we have no interest rate swap agreements outstanding.

Treasury Locks. During the fourth quarter of 2002, we entered into seven treasury lock transactions, each with an original maturity of either January 31, 2003 or April 15, 2003. A treasury lock is a specialized agreement that fixes the price (or yield) on a specific U.S. treasury security for an established period of time. The purpose of these financial instruments was to hedge the underlying treasury interest rate associated with our anticipated issuance of debt in early 2003 to partially refinance the Mid-America and Seminole acquisitions. Our treasury lock transactions are accounted for as cash flow hedges under SFAS No. 133. The notional amounts of the treasury lock transactions totaled $550 million, with a total treasury lock rate of approximately 4%.

We elected to settle all of the treasury locks during the first quarter of 2003 in connection with our issuance of Senior Notes C and D. For additional information regarding our debt, please read “Our liquidity and capital resources – Our debt obligations” on page 57 of this quarterly report. The settlement of the treasury locks resulted in our receipt of $5.4 million in cash.

The fair value of these instruments at December 31, 2002 was a current liability of $3.8 million offset by a current asset of $0.2 million. The $3.6 million net liability was recorded as a component of comprehensive income on that date, with no impact on 2002 net income. As a result of settlement of the treasury locks, the $3.6 million net liability was reclassified out of accumulated other comprehensive income in Partners’ Equity to offset the current asset and liabilities we recorded at December 31, 2002, with no impact on 2003 net income. For additional information regarding our treasury lock transactions, please read our footnote 11 of our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

Item 4. CONTROLS AND PROCEDURES.

As of the end of the period covered by this report, the CEO and CFO of the General Partner of Enterprise Products Partners L.P. and Enterprise Products Operating L.P. (collectively the “registrants”) have evaluated the effectiveness of the registrants’ disclosure controls and procedures, including internal control over financial reporting. These disclosure controls and procedures are those controls and other procedures we maintain, which are designed to provide reasonable assurance that all of the information required to be disclosed by the registrants in all of their combined and separate periodic reports filed with the SEC is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by the registrants in their reports filed or submitted under the Securities Exchange Act of 1934 is accumulated and communicated to our management, including the CEO and CFO of the General Partner, as appropriate to allow those persons to make timely decisions regarding required disclosure.

In the course of their evaluation of the registrants’ disclosure controls and procedures, the CEO and CFO noted no significant deficiencies or material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrants’ ability to record, process, summarize and report financial information. In addition, no fraud, whether or not material, was detected involving management or other employees who have a significant role in the registrants’ internal control over financial reporting. In addition, there has not been any change in the registrants’ disclosure controls and procedures during the quarter that has materially affected, or is reasonably likely to materially affect, the registrants’ internal control over financial reporting. Since no significant deficiencies or material weaknesses were detected in the registrants’ disclosure controls and procedures, no corrective actions regarding these controls and procedures are currently warranted.

PART II. OTHER INFORMATION.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K.

(a) Exhibits.

Exhibit No.		Exhibit*

2.1		Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 26, 2000).
2.2		Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 8, 2002.)
2.3		Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 8, 2002).
2.4		Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Form 8-K filed August 12, 2002).
2.5		Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 12, 2002).
3.1		First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC dated as of September 17, 1999 (incorporated by reference to Exhibit 99.8 to Form 8-K/A-l filed October 27, 1999).
3.2		Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC dated as of September 19, 2002 (incorporated by reference to Exhibit 3.2 to Form 10-K filed March 31, 2003).
3.3		Third Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated May 15, 2002 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 13, 2002).
3.4		Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated August 7, 2002 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed August 13, 2002).
3.5		Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P. dated December 17, 2002 (incorporated by reference to Exhibit 3.5 to Form 8-K filed December 17, 2002).
3.6		Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-1/A filed July 21, 1998).
4.1		Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
4.2		First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.3		Global Note representing $350 million principal amount of 6.375% Series A Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.3 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.4		Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.5		Registration Rights Agreement dated as of January 22, 2003, among Enterprise Products Operating L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.5 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
4.6		Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).

4.7		Rule 144 A Global Note representing $499.2 million principal amount of 6.875% Series A Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Form 10-K filed March 31, 2003).
4.8		Regulation S Global Note representing $800,000 principal amount of 6.875% Series A Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.6 to Form 10-K filed March 31, 2003).
4.9		Form of Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 10-K filed March 31, 2003).
4.10		Registration Rights Agreement dated as of February 14, 2003, among Enterprise Products Operating L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.10 to Form 10-K filed March 31, 2003).
4.11		Global Note representing $350 million principal amount of 8.25% Senior Notes due 2005 (incorporated by reference to Exhibit 4.2 to Form 8-K filed March 10, 2000).
4.12		Global Note representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
4.13		Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998).
4.14		$250 Million Multi-Year Revolving Credit Facility dated as of November 17, 2000, among Enterprise Products Operating L.P., First Union National Bank, as Administrative Agent, Bank One, NA, as Documentation Agent, the Chase Manhattan Bank, as Syndication Agent, and the several banks from time to time parties thereto, with First Union Securities, Inc. and Chase Securities Inc. as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 4.2 to Form 8-K filed January 24, 2001).
4.15		$150 Million 364-Day Revolving Credit Facility November 17, 2000, among Enterprise Products Operating L.P., First Union National Bank, as Administrative Agent, Bank One, NA, as Documentation Agent, the Chase Manhattan Bank, as Syndication Agent, and the several banks from time to time parties thereto, with First Union Securities, Inc. and Chase Securities Inc. as Joint Lead Arrangers and Joint Book Managers (incorporated by reference to Exhibit 4.3 to Form 8-K filed January 24, 2001).
4.16		Guaranty Agreement dated as of November 17, 2000, by Enterprise Products Partners L.P. in favor of First Union National Bank, as Administrative Agent, with respect to the $250 Million Multi-Year Revolving Credit Facility included as Exhibit 4.4 above (incorporated by reference to Exhibit 4.4 to Form 8-K filed January 24, 2001).
4.17		Guaranty Agreement dated as of November 17, 2000, by Enterprise Products Partners L.P. in favor of First Union National Bank, as Administrative Agent, with respect to the $150 Million 364-Day Revolving Credit Facility (incorporated by reference to Exhibit 4.5 to Form 8-K filed January 24, 2001).
4.18		First Amendment to Multi-Year Credit Facility dated April 19, 2001 (incorporated by reference to Exhibit 4.12 to Form 10-Q filed May 14, 2001).
4.19		Second Amendment to Multi-Year Revolving Credit Facility dated April 14, 2002 (incorporated by reference to Exhibit 4.14 to Form 10-Q filed May 14, 2002).
4.20		Third Amendment to Multi-Year Revolving Credit Facility dated July 31, 2002 (incorporated by reference to Exhibit 4.1 to Form 10-Q filed August 12, 2002).
4.21		Fourth Amendment to 364-Day Revolving Credit Facility dated effective as of November 15, 2002 (incorporated by reference to Exhibit 4.19 to Form 10-Q filed November 13, 2002).
4.22		First Amendment to 364-Day Credit Facility dated November 6, 2001, effective as of November 16, 2001 (incorporated by reference to Exhibit 4.13 to Form 10-Q filed August 13, 2002).
4.23		Second Amendment to 364-Day Revolving Credit Facility dated April 24, 2002 (incorporated by reference to Exhibit 4.15 to Form 10-Q filed May 14, 2002).
4.24		Third Amendment to 364-Day Revolving Credit Facility dated July 31, 2002 (incorporated by reference to Exhibit 4.2 to Form 8-K filed August 12, 2002).
4.25		Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit "B" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).

4.26		Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "E" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.27		Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit "C" to Schedule 13D filed September 27, 1999 by Tejas Energy, LLC).
4.28		Amendment No. 1, dated September 12, 2003, to Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit 4.1 to Form 8-K filed September 15, 2003).
4.29#		364-Day Revolving Credit Agreement dated as of October 30, 2003, among Enterprise Products Operating L.P., Wachovia Bank, National Association, as Administrative Agent, Bank One, N.A., as Syndication Agent, Royal Bank of Canada, The Bank of Nova Scotia and Suntrust Bank, as Co-Documentation Agents, and the several lenders from time to time parties thereto, with Wachovia Capital Markets, LLC and Banc One Capital Markets, Inc., as Joint Lead Arrangers, and Wachovia Capital Markets, LLC, as Sole Manager.
4.30#		Guaranty Agreement dated as of October 30, 2003 by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent, with respect to 364-Day Revolving Credit Facility.
4.31#		Fourth Amendment to Multi-Year Revolving Credit Facility dated October 30, 2003.
31.1#		Sarbanes-Oxley Section 302 certification of O.S. Andras for Enterprise Products Partners L.P. for the September 30, 2003 quarterly report on Form 10-Q.
31.2#		Sarbanes-Oxley Section 302 certification of O.S. Andras for Enterprise Products Operating L.P. for the September 30, 2003 quarterly report on Form 10-Q.
31.3#		Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the September 30, 2003 quarterly report on Form 10-Q.
31.4#		Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Operating L.P. for the September 30, 2003 quarterly report on Form 10-Q.
32.1#		Sarbanes-Oxley Section 1350 certification of O.S. Andras for the September 30, 2003 quarterly report on Form 10-Q.
32.2#		Sarbanes-Oxley Section 1350 certification of Michael A. Creel for the September 30, 2003 quarterly report on Form 10-Q.

*	With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323 and the Commission file number for Enterprise Products Operating L.P. is 333-93239-01.
#	Filed with this report.

(b) Reports on Form 8-K.

July 16, 2003 filing, Items 5, 9 and 12. On July 16, 2003, we issued a press release declaring our second quarter 2003 quarterly cash distribution rate and providing earnings guidance for the three and six month periods ending June 30, 2003. A copy of this press release was furnished as an exhibit.

July 16, 2003 filing, Items 5 and 7. On May 1, 2003, 10,734,936 of EPCO’s Subordinated Units converted to Common Units. As a result of this conversion, we updated the description of our Common Units. Exhibits related to our Third Amended and Restated Agreement of Limited Partnership were incorporated by reference.

July 31, 2003 filing, Items 5, 7 and 12. On July 31, 2003, we issued a press release regarding our financial results for the six months ended June 30, 2003 and 2002. A copy of the earnings press release was furnished as an exhibit.

September 15, 2003 filing, Items 5 and 7. On September 12, 2003, an affiliate of EPCO acquired Shell’s 30% interest in our General Partner. As a result of this transaction, entities controlled by Dan L. Duncan, the Chairman of the General Partner, own 100% of the membership interests in the General Partner. In connection with this transaction, our Unitholder Rights Agreement was amended to, among other things, eliminate Shell’s right to participate in our policy-making functions and to eliminate certain preemptive rights of Shell. In addition, the three designees of Shell that had been serving on the Board of Directors of the General Partner resigned their positions on September 12, 2003. The amended Unitholder Rights Agreement and a press release announcing the transaction were attached as exhibits.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this combined quarterly report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas on November 13, 2003.



	ENTERPRISE PRODUCTS PARTNERS L.P.
	(A Delaware Limited Partnership)
	ENTERPRISE PRODUCTS OPERATING L.P.
	(A Delaware Limited Partnership)

	By:	Enterprise Products GP, LLC,
		as General Partner for both registrants



	By:	/s/ Michael J. Knesek
	Name:	Michael J. Knesek
	Title:	Vice President, Controller and Principal
		Accounting Officer of the General Partner

EXPLANATORY NOTE

Glossary

Glossary (continued)

9. CAPITAL STRUCTURE

13. UNIT OPTION PLAN ACCOUNTING

1. GENERAL

2. RECENTLY ISSUED ACCOUNTING STANDARDS

3. BUSINESS COMBINATIONS

4. INVENTORIES

5. PROPERTY, PLANT AND EQUIPMENT

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

8. DEBT OBLIGATIONS

9. CAPITAL STRUCTURE

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

11. FINANCIAL INSTRUMENTS

12. SEGMENT INFORMATION

13. UNIT OPTION PLAN ACCOUNTING

14. SUBSEQUENT EVENTS

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

For the three and nine months ended September 30, 2003 and 2002.

Our results of operations

Our liquidity and capital resources

Material contractual obligations

Related party transactions

Recent accounting developments

Our critical accounting policies

Other items

Cautionary statement regarding forward-looking information and risk factors

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Item 4. CONTROLS AND PROCEDURES.

PART II. OTHER INFORMATION.Item 6. EXHIBITS AND REPORTS ON FORM 8-K.

SIGNATURES

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.

PART II. OTHER INFORMATION.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K.