EXPLANATORY NOTE

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

1. GENERAL

2. RECENTLY ISSUED ACCOUNTING STANDARDS

3. BUSINESS ACQUISITIONS

4. INVENTORIES

5. PROPERTY, PLANT AND EQUIPMENT

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

Goodwill

8. DEBT OBLIGATIONS

9. CAPITAL STRUCTURE

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

11. FINANCIAL INSTRUMENTS

12. SEGMENT INFORMATION

13. PROVISION FOR INCOME TAXES

14. UNIT OPTION PLAN ACCOUNTING

15. EARNINGS PER UNIT

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

1. GENERAL

2. RECENTLY ISSUED ACCOUNTING STANDARDS

3. BUSINESS ACQUISITIONS

4. INVENTORIES

5. PROPERTY, PLANT AND EQUIPMENT

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

Goodwill

8. DEBT OBLIGATIONS

9. CAPITAL STRUCTURE

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

11. FINANCIAL INSTRUMENTS

12. SEGMENT INFORMATION

13. PROVISION FOR INCOME TAXES

14. UNIT OPTION PLAN ACCOUNTING

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

For the three months ended March 31, 2003 and 2002.

Our results of operations

Our liquidity and capital resources

Material contractual obligations

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

SARBANES-OXLEY SECTION 302 CERTIFICATIONS

EXPLANATORY NOTE

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

1. GENERAL

2. RECENTLY ISSUED ACCOUNTING STANDARDS

3. BUSINESS ACQUISITIONS

4. INVENTORIES

5. PROPERTY, PLANT AND EQUIPMENT

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

Goodwill

8. DEBT OBLIGATIONS

9. CAPITAL STRUCTURE

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

11. FINANCIAL INSTRUMENTS

12. SEGMENT INFORMATION

13. PROVISION FOR INCOME TAXES

14. UNIT OPTION PLAN ACCOUNTING

15. EARNINGS PER UNIT

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

1. GENERAL

2. RECENTLY ISSUED ACCOUNTING STANDARDS

3. BUSINESS ACQUISITIONS

4. INVENTORIES

5. PROPERTY, PLANT AND EQUIPMENT

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

7. INTANGIBLE ASSETS AND GOODWILL

Intangible assets

Goodwill

8. DEBT OBLIGATIONS

9. CAPITAL STRUCTURE

10. SUPPLEMENTAL CASH FLOWS DISCLOSURE

11. FINANCIAL INSTRUMENTS

12. SEGMENT INFORMATION

13. PROVISION FOR INCOME TAXES

14. UNIT OPTION PLAN ACCOUNTING

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

For the three months ended March 31, 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

SARBANES-OXLEY SECTION 302 CERTIFICATIONS

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

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

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

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 March 31, 2003

[ ] 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)

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

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

Yes [X] No [ ]

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

Yes [X] No [ ]

There were 167,062,202 Common Units, 21,409,868 Subordinated Units and 10,000,000 Special Units of Enterprise Products Partners L.P. outstanding at May 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.

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.

The Operating Partnership’s Form 10-Q for the first quarter of 2003 was filed originally under CIK #0001061219 on May 13, 2003. Per instructions from EDGAR filing support on August 6, 2003, the Form 10-Q for the Operating Partnership was retransmitted to the Securities and Exchange Commission EDGAR system on August 6, 2003 to the co-registrant CIK # 0001102995.

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

		Page No.
	PART I
Glossary

Item 1.	Financial Statements.
Item 1A.	Enterprise Products Partners L.P.	1
Item 1B.	Enterprise Products Operating L.P.	21

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operation	40

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	57

Item 4.	Controls and Procedures	58

	PART II

Item 6.	Exhibits and Reports on Form 8-K.	59

Signature Page		62
Sarbanes-Oxley Section 302 certifications		63

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
BBtus	Billion British thermal units, a measure of heating value
BEF	Belvieu Environmental Fuels, an equity investment of EPOLP
Belle Rose	Belle Rose NGL Pipeline LLC, an equity investment of EPOLP
BPD	Barrels per day
BRF	Baton Rouge Fractionators LLC, an equity investment of EPOLP
BRPC	Baton Rouge Propylene Concentrator, LLC, an equity investment of EPOLP
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
CPG	Cents per gallon
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, an affiliate of the Company and our ultimate parent company (including its affiliates)
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")
EPU	Earnings per Unit
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
LIBOR	London interbank offered rate
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)
MMBbls	Millions of barrels
MMBtu/d	Million British thermal units per day, a measure of heating value
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

Glossary (continued)


MTBE	Methyl tertiary butyl ether
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)
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
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
S & P	Standard and Poor's Rating Services
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 interest 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

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.

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

ASSETS	March 31, 2003			December 31, 2002
Current Assets
Cash and cash equivalents (includes restricted cash of $18,757 at
March 31, 2003 and $8,751 at December 31, 2002)	$	41,346		$	22,568
Accounts and notes receivable - trade, net of allowance for doubtful accounts
of $21,249 at March 31, 2003 and $21,196 at December 31, 2002		482,965			399,187
Accounts receivable - affiliates		406			228
Inventories		101,962			167,369
Prepaid and other current assets		22,432			48,216

Total current assets		649,111			637,568
Property, Plant and Equipment, Net		2,845,993			2,810,839
Investments in and Advances to Unconsolidated Affiliates		386,249			396,993
Intangible assets, net of accumulated amortization of $29,136 at
March 31, 2003 and $25,546 at December 31, 2002		274,072			277,661
Goodwill		81,547			81,547
Deferred Tax Asset		13,113			15,846
Other Assets		16,305			9,818

Total	$	4,266,390		$	4,230,272

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Current maturities of debt	$	15,000		$	15,000
Accounts payable-trade		74,364			67,283
Accounts payable-affiliates		35,162			40,772
Accrued gas payables		575,504			489,562
Accrued expenses		19,987			35,760
Accrued interest		17,974			30,338
Other current liabilities		23,994			42,641

Total current liabilities		761,985			721,356
Long-Term Debt		1,986,636			2,231,463
Other Long-Term Liabilities		7,663			7,666
Minority Interest		71,273			68,883
Commitments and Contingencies
Partners' Equity
Common Units (156,357,266 Units outstanding at March 31, 2003
and 141,694,766 at December 31, 2002)		1,181,052			949,835
Subordinated Units (32,114,804 Units outstanding at March 31, 2003
and December 31, 2002)		111,863			116,288
Special Units (10,000,000 Units outstanding at March 31, 2003
and December 31, 2002)		143,926			143,926
Treasury Units acquired by Trust, at cost (859,200 Common Units
outstanding at March 31, 2003 and December 31, 2002)		(17,808	)		(17,808	)
General Partner		14,514			12,223
Accumulated Other Comprehensive Income (Loss)		5,286			(3,560	)

Total Partners' Equity		1,438,833			1,200,904

Total	$	4,266,390		$	4,230,272

See Notes to Unaudited Consolidated Financial Statements

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

	For the Three Months Ended March 31,
	2003			2002
REVENUES
Revenues from consolidated operations
Third parties	$	1,348,782		$	571,246
Related parties		132,804			90,808

Total		1,481,586			662,054

COST AND EXPENSES
Operating costs and expenses
Third parties		1,152,302			518,049
Related parties		234,402			146,503
Selling, general and administrative
Third parties		5,087			2,009
Related parties		6,384			5,953

Total		1,398,175			672,514

EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES		1,621			9,227

OPERATING INCOME (LOSS)		85,032			(1,233	)

OTHER INCOME (EXPENSE)
Interest expense		(41,911	)		(18,513	)
Interest income from related parties					30
Dividend income from unconsolidated affiliates		2,601			954
Interest income - other		200			1,334
Other, net		34			52

Other income (expense)		(39,076	)		(16,143	)

INCOME (LOSS) BEFORE PROVISION FOR INCOME
TAXES AND MINORITY INTEREST		45,956			(17,376	)
PROVISION FOR INCOME TAXES		(3,129	)

INCOME (LOSS) BEFORE MINORITY INTEREST		42,827			(17,376	)
MINORITY INTEREST		(2,322	)		173

NET INCOME (LOSS)		40,505			(17,203	)
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		(68	)

COMPREHENSIVE INCOME (LOSS)	$	49,351		$	(17,203	)

ALLOCATION OF NET INCOME (LOSS) TO:
Limited partners	$	36,368		$	(18,449	)

General partner	$	4,137		$	1,246

BASIC EARNINGS PER UNIT
Income (loss) before minority interest	$	0.21		$	(0.13	)

Net income (loss) per Common and Subordinated unit	$	0.20		$	(0.13	)

DILUTED EARNINGS PER UNIT
Income (loss) before minority interest	$	0.20		$	(0.13	)

Net income (loss) per Common, Subordinated
and Special unit	$	0.19		$	(0.13	)

See Notes to Unaudited Consolidated Financial Statements

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

	For the Three Months Ended March 31,
	2003			2002
OPERATING ACTIVITIES
Net income (loss)	$	40,505		$	(17,203	)
Adjustments to reconcile net income (loss) to cash flows provided
by (used for) operating activities:
Depreciation and amortization in operating costs and expenses		27,657			17,238
Depreciation in selling, general and administrative costs		22			7
Amortization in interest expense		11,582			702
Equity in income of unconsolidated affiliates		(1,621	)		(9,227	)
Distributions received from unconsolidated affiliates		15,626			14,438
Operating lease expense paid by EPCO		2,251			2,281
Minority interest		2,321			(173	)
Loss on sale of assets		4			14
Deferred income tax expense		2,733
Changes in fair market value of financial instruments		(28	)		30,141
Net effect of changes in operating accounts		50,497			(48,191	)

Operating activities cash flows		151,549			(9,973	)

INVESTING ACTIVITIES
Capital expenditures		(23,835	)		(17,112	)
Proceeds from sale of assets		34			10
Business acquisitions, net of cash received		(28,783	)		(368,631	)
Investments in and advances to unconsolidated affiliates		(20,509	)		(10,752	)

Investing activities cash flows		(73,093	)		(396,485	)

FINANCING ACTIVITIES
Borrowings under debt agreements		896,210			383,000
Repayments of debt		(1,141,000	)		(20,000	)
Debt issuance costs		(6,683	)
Distributions paid to partners		(69,155	)		(47,374	)
Distributions paid to minority interests		(2,517	)		(485	)
Contributions from minority interests		2,631			62
Proceeds from issuance of Common Units		255,482
Treasury Units purchased					(2,015	)
Settlement of treasury lock financial instruments		5,354
Increase in restricted cash		(10,006	)		(8,769	)

Financing activities cash flows		(69,684	)		304,419

NET CHANGE IN CASH AND CASH EQUIVALENTS		8,772			(102,039	)
CASH AND CASH EQUIVALENTS, JANUARY 1		13,817			132,071

CASH AND CASH EQUIVALENTS, MARCH 31	$	22,589		$	30,032

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		30,096			6,272								4,137						40,505
Leases paid by EPCO		1,846			382								23						2,251
Cash distributions to partners		(53,652	)		(11,079	)							(4,424	)					(69,155	)
Proceeds from issuance of
Common Units		252,927											2,555						255,482
Reclassification of change in
value of treasury lock financial
instruments recorded as
cash flow hedges (see Note 11)																3,560			3,560
Cash gains on settlement of treasury
lock financial instruments
recorded as cash flow hedges (see Note 11)																5,354			5,354
Amortization of cash gains on
settlement of treasury lock
financial instruments to interest
expense in earnings (see Note 11)																(68	)		(68	)

Balance, March 31, 2003	$	1,181,052		$	111,863		$	143,926	$	(17,808	)	$	14,514		$	5,286		$	1,438,833

See Notes to Unaudited Consolidated Financial Statements

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 March 31, 2003 and consolidated results of operations and cash flows for the three months ended March 31, 2003 and 2002. 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 report on Form 10-Q. We own 98.9899% of the Operating Partnership and act as guarantor of certain debt obligations of the Operating Partnership. 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 generally accepted accounting principles 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 months ended March 31, 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 terms are described 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 14 for the pro forma effects to net income and earnings per Unit as if we had used the fair-value based method of accounting for Unit options.

The following recently issued accounting standards have been adopted and implemented by us:

• SFAS No. 143, "Accounting for Asset Retirement Obligations";

• SFAS No. 146, "Accounting for Costs Associated with Exit and Disposal Activities";

• SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure"; and,

• FIN No. 45, "Guarantor's Accounting and Disclosure Requirement from Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

We are currently evaluating the provisions of FIN No. 46, Consolidation of Variable Interest Entities.

SFAS No. 143. We adopted this standard as of January 1, 2003. This statement establishes accounting standards for the recognition and measurement of a liability for an asset

retirement obligation (“ARO”) and the associated asset retirement cost. Under the provisions of this standard, we reviewed our long-lived assets for ARO liabilities and identified such liabilities in several operational areas. These include ARO liabilities related to (i) easements over property not currently owned by us and (ii) statutory regulatory requirements for abandonment or retirement of certain currently operated facilities.

As a result of our analysis of the identified AROs, we were not required to recognize such potential liabilities. Our rights to the easements are renewable and only require retirement action upon nonrenewal of the easement agreements. We currently plan to renew all such easement agreements and use these properties indefinitely. Therefore, the ARO liability is not estimable for such easements. If we decide to not renew these agreements, an ARO liability would be recorded at that time. ARO liabilities related to statutory regulatory requirements for abandonment or retirement of certain currently operated facilities were also identified. 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 occurred. Certain Gulf of Mexico natural gas pipelines, in which we have an equity interest, have identified ARO’s relating to regulatory requirements. There is no current intention to abandon or retire these pipelines. If these pipelines were abandoned or retired, an ARO liability would then be disclosed.

SFAS No. 146. 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 a commitment to exit or disposal plan. We determined that this standard had no material impact on our financial statements.

SFAS No. 148. 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 14.

SFAS No. 149. On April 30, 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies accounting 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 20, 2003, for hedging relationships designated after June 30, 2003, and to certain preexisting contracts. We will adopt SFAS No. 149 on a prospective basis at its effective date on July 1, 2003. We are currently evaluating the impact that SFAS No. 149 will have on our financial statements.

FIN 45. 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. In January 2003, FIN 46, an interpretation of ARB No. 51, Consolidated Financial Statements, was issued to address perceived weaknesses in accounting for entities commonly known as special-purpose or off-balance-sheet entities, but the guidance applies to a larger population of entities. FIN 46 provides guidance for identifying the party with a controlling financial interest resulting from arrangements or financial interests rather than from voting interests. FIN 46 defines the term “variable interest entity” (or “VIE”) and is based on the premise that if a business enterprise has a controlling financial interest in a VIE, the assets, liabilities, and results of the activities of the VIE should be included in the consolidated financial statements of the business enterprise. FIN 46 applies immediately to VIEs created after January 31, 2003 and to VIEs in which an enterprise obtains an interest after that date. For variable interests in VIEs created before February 1, 2003, FIN 46 applies to public enterprises no later than the beginning of the first interim or annual period beginning after June 15, 2003. This FIN may be applied prospectively with the cumulative-effect adjustment as of the date on which it is first applied or by restating previously issued financial statements for one

or more years with the cumulative-effect adjustment as of the beginning of the first year restated. We are currently studying the provisions of FIN 46. Based upon our initial interpretation of FIN 46, we do not believe that this guidance will have a material effect on our financial statements.

During the three months ended March 31, 2003, we acquired entities owning the Port Neches Pipeline and purchased the remaining 50% ownership interest in EPIK. We also made minor adjustments to the allocation of the purchase price we paid to acquire indirect interests in the Mid-America and Seminole pipelines. Due to the immaterial nature of each, individually and in the aggregate, our discussion of each of these transactions is limited to the following:

Acquisition of Port Neches Pipeline. In March 2003, we acquired two entities owning the Port Neches Pipeline (formerly known as the Quest Pipeline) for $14.2 million. The 70-mile Port Neches Pipeline transports high-purity grade isobutane produced at our facilities in Mont Belvieu to consumers in Port Neches, Texas.

Acquisition of remaining 50% interest in EPIK. In March 2003, we purchased the remaining 50% ownership interests in EPIK for $14.4 million (which is net of cash received of $4.6 million). EPIK owns an NGL export terminal located in southeast Texas. As a result of this acquisition, EPIK became a wholly-owned subsidiary of ours (previously, it had been an unconsolidated affiliate).

Our preliminary allocation of the purchase price of each transaction is as follows:

			Port Neches Pipeline			Other
Prepaid and other current assets	$	1,188		$	44				$	1,232
Property, plant and equipment		31,585			14,203			188		45,976
Investments in and advances to unconsolidated affiliates		(17,247	)							(17,247	)
Accrued expenses		(1,102	)		(19	)				(1,121	)
Other current liabilities		(35	)		(24	)				(59	)
Minority interest								4		4

Total purchase price	$	14,389		$	14,204		$	192	$	28,785

Our inventories were as follows at the dates indicated:


Working inventory	$	101,962	$	131,769
Forward-sales inventory				35,600

Inventory	$	101,962	$	167,369

Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs and petrochemical products that are available for sale by our marketing activities. The forward sales inventory was 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 average 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 three months ended March 31, 2003 and 2002, we recognized $10.4 million and $0.1 million, respectively, of such LCM adjustments. The majority of these write-downs were taken against NGL inventories.

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


Plants and pipelines	5-35	$2,901,451	$2,860,180
Underground and other storage facilities	5-35	284,214	283,114
Transportation equipment	3-35	5,223	5,118
Land		23,825	23,817
Construction in progress		68,848	49,586

Total		3,283,561	3,221,815
Less accumulated depreciation		437,568	410,976

Property, plant and equipment, net		$2,845,993	$2,810,839

Depreciation for the three-month periods ended March 31, 2003 and 2002 was $27.7 million and $17.2 million, respectively.

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 operating 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:


Accounted for on equity basis:
Fractionation:
BRF	32.25%	$	28,214	$	28,293
BRPC	30.00%		17,392		17,616
Promix	33.33%		41,049		41,643
La Porte	50.00%		5,619		5,737
OTC	50.00%		5,493		2,178
Pipeline:
EPIK (see Note 3)	50.00%				11,114
Wilprise	37.35%		8,508		8,566
Tri-States	33.33%		25,571		25,552
Belle Rose	41.67%		10,904		11,057
Dixie	19.88%		37,461		36,660
Starfish	50.00%		30,716		28,512
Neptune	25.67%		76,928		77,365
Nemo	33.92%		12,004		12,423
Evangeline	49.50%		2,501		2,383
Octane Enhancement:
BEF	33.33%		50,889		54,894
Accounted for on cost basis:
Processing:
VESCO	13.10%		33,000		33,000

Total		$	386,249	$	396,993

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

	Ownership		For the Three Months Ended March 31,
	Percentage		2003		2002
Fractionation:
BRF	32.25%	$	142		$	549
BRPC	30.00%		148			249
Promix	33.33%		260			1,043
La Porte	50.00%		(181	)		(92	)
OTC	50.00%		(85	)		(110	)
Pipelines:
EPIK (see Note 3)	50.00%		1,818			1,683
Wilprise	37.35%		163			147
Tri-States	33.33%		549			469
Belle Rose	41.67%		(29	)		74
Dixie	19.88%		801			717
Starfish	50.00%		1,149			812
Neptune	25.67%		10			778
Nemo	33.92%		336			(22	)
Evangeline	49.50%		(19	)		(76	)
Octane Enhancement:
BEF	33.33%		(3,441	)		3,006

Total		$	1,621		$	9,227

The following tables represent 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
	March 31, 2003									March 31, 2002
	Revenues		Operating Inc (Loss)			Net Inc (Loss)			Revenues		Operating Income		Net Income
Pipelines	$	91,974	$	20,927		$	14,661		$	67,847	$	18,988	$	14,581
Fractionation		18,114		1,524			1,505			18,040		5,352		5,372
Octane Enhancement		45,651		(10,356	)		(10,322	)		47,929		8,978		9,019

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 March 31, 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	March 31, 2003	December 31, 2002
Fractionation	20-35 years	8,828		7,319	7,429
Pipelines	35 years (1)	41,943	9,246	47,338	47,637

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

For the three months ended March 31, 2003 and 2002, we recorded $0.4 million and $0.5 million, respectively, of excess cost amortization which is reflected in our equity in income from unconsolidated affiliates.

Purchase of remaining 50% interest in EPIK

As discussed in Note 3, we purchased the remaining 50% ownership interests in EPIK in March 2003. As a result of this acquisition, EPIK became a wholly-owned subsidiary of ours. 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.

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

			At March 31, 2003
	Gross Value		Accum. Amort.			Carrying Value		Accum. Amort.			Carrying Value
Shell natural gas processing agreement	$	206,216	$	(25,777	)	$	180,439	$	(23,015	)	$	183,201
Mont Belvieu Storage II contracts		8,127		(290	)		7,837		(232	)		7,895
Mont Belvieu Splitter III contracts		53,000		(1,767	)		51,233		(1,388	)		51,612
Toca-Western natural gas processing contracts		11,187		(466	)		10,721		(326	)		10,861
Toca-Western NGL fractionation contracts		20,042		(836	)		19,206		(585	)		19,457
Venice contracts (a)		4,636					4,636					4,635

Total	$	303,208	$	(29,136	)	$	274,072	$	(25,546	)	$	277,661



(a) Amortization scheduled to begin when contracted-volumes begin to be processed in in the late 2003

The following table shows amortization expense associated with our intangible assets for the three months ended March 31, 2003 and 2002:

		For the Three Months Ended March 31,
		2003		2002
Shell natural gas processing agreement	$	2,762	$	2,761
Mont Belvieu Storage II contracts		58		60
Mont Belvieu Splitter III contracts		379		252
Toca-Western natural gas processing contracts		140
Toca-Western NGL fractionation contracts		250

Total	$	3,589	$	3,073

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 March 31, 2003 and December 31, 2002):

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

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

	March 31, 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	$	32,000			99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005		225,000			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		2,006,000			2,245,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt		1,712			1,774
Less unamortized discount on:
Senior Notes A		(71	)		(81	)
Senior Notes B		(222	)		(230	)
Senior Notes D		(5,783	)
Less current maturities of debt		(15,000	)		(15,000	)

Long-term debt	$	1,986,636		$	2,231,463

Letters of credit. At March 31, 2003 and December 31, 2002, we had $75 million of standby letter of credit capacity under our Multi-Year Revolving Credit facility. We had $25.7 million of letters of credit outstanding under this facility at March 31, 2003 and $2.4 million outstanding at December 31, 2002.

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

New debt obligations issued during first quarter of 2003

During the first quarter of 2003, we completed the issuance of $850 million of private placement debt (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. 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 C due February 1, 2013 (“Senior Notes C”), from which we received net proceeds before offering expenses of approximately $347.7 million. These 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 April 2003, we initiated an offer to exchange 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 notes were sold at a discount of 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.

Repayment of 364-Day Term Loan

Our Operating Partnership entered into a $1.2 billion senior unsecured 364-day term loan to initially fund the acquisition of indirect interests in Mid-America and Seminole in July 2002. We used $178.5 million of the $182.5 million in proceeds from our October 2002 equity offering to partially repay this loan. We 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 by February 2003.

Covenants

We were in compliance with the various covenants of our debt agreements at March 31, 2003 and December 31, 2002.

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 three months ended March 31, 2003:

	Range of interest rates paid	Weighted- average interest rate paid
364-Day Term Loan (a)	2.59% - 2.88%	2.85%
364-Day Revolving Credit facility	2.47% - 4.25%	2.52%
Multi-Year Revolving Credit facility	1.92% - 2.00%	1.97%



(a) This facility was repaid in February 2003

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

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

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 the 364-Day Term Loan. The remaining balance of proceeds was used for working capital purposes and offering expenses.

Our partnership agreement stipulates that the Subordinated Units may undergo an early conversion to Common Units if certain criteria are 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. The remaining 21,409,868 Subordinated Units will convert to Common Units on August 1, 2003 if the remaining criteria are met.

The following table details the Unit activity within each class of our limited partner interests during the three months ended March 31, 2003 and the outstanding balance of each at March 31, 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

Balance, March 31, 2003	156,357,266	32,114,804	10,000,000	859,200

The net effect of changes in operating accounts and liabilities is as follows:

	For the Three Months Ended March 31,
	2003			2002
(Increase) decrease in:
Accounts and notes receivable	$	(83,955	)	$	978
Inventories		76,079			(31,748	)
Prepaid and other current assets		15,238			(2,494	)
Other assets		(503	)		(3,186	)
Increase (decrease) in:
Accounts payable		1,471			(9,559	)
Accrued gas payable		85,942			31,515
Accrued expenses		(16,894	)		(6,588	)
Accrued interest		(12,364	)		(16,137	)
Other current liabilities		(14,517	)		(10,892	)
Other liabilities					(80	)

Net effect of changes in operating accounts	$	50,497		$	(48,191	)

During the three months ended March 31, 2003, we completed two small business acquisitions and made minor adjustments to the purchase price allocation of the Mid-America and Seminole acquisitions. These acquisitions and adjustments affected various balance sheet accounts (see Note 3). The 2002 period reflects our acquisition of Diamond-Koch’s Mont Belvieu NGL and petrochemical storage business in January 2002 and their adjacent propylene fractionation business (Splitter III) in February 2002.

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 three months ended March 31, 2002, we recognized a net $30.1 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 quarter of 2003 and the non-cash change in fair value of these instruments was an increase of $28 thousand.

Cash and cash equivalents (as shown on our Statements of Consolidated Cash Flows) excludes restricted cash amounts held by a brokerage firm as margin deposits associated with our financial instruments portfolio and for our physical purchase transactions made on the NYMEX exchange. The restricted cash balance at March 31, 2003 and December 31, 2002 was $18.8 million and $8.8 million, respectively.

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

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 three months of 2003, we held a limited number of commodity financial instruments from which we recorded a loss of $0.9 million ($0.1 million was attributable to the Processing segment and the remainder to the Pipelines segment). The fair value of open positions at March 31, 2003 was a receivable of approximately $2 thousand.

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 transactions 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 these transactions totaled $550 million, with a total treasury lock rate of approximately 4%.

Our treasury lock transactions are accounted for as cash flow hedges under SFAS No. 133. 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 net $3.6 million non-cash mark-to-market liability was recorded as a component of comprehensive income on that date, with no impact to current earnings.

We settled all of the treasury locks by early February 2003 in connection with our issuance of Senior Notes C and D (see Note 8). The settlement of these instruments resulted in our receipt of $5.4 million of 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. With the 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 to earnings.

We have five reportable operating segments: Pipelines, Fractionation, Processing, Octane Enhancement and Other. The 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 Chief Executive Officer 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 equity interest in BEF, a facility that produces motor gasoline additives to enhance octane (currently producing MTBE). The Other operating segment consists of fee-based marketing services and various operational support activities.

which the partnership does not have the payment obligation and gains and losses on the sale of assets) from segment revenues, with both segment totals before elimination of intercompany transactions. Intercompany accounts and transactions are eliminated in consolidation in accordance with GAAP. Segment gross operating margin is also exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. We have provided a reconciliation of total gross operating margin (a non-GAAP performance measure) to operating income.

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

	For the Three Months Ended March 31,
	2003			2002
Revenues (a)	$	1,481,586		$	662,054
Less operating costs and expenses (a)		(1,386,704	)		(664,552	)
Add equity in income of unconsolidated affiliates (b)		1,621			9,227
Subtotal		96,503			6,729
Add: Depreciation and amortization in operating costs and expenses (c)		27,657			17,238
Retained lease expense, net in operating expenses allocable to us (d)		2,251			2,281
Retained lease expense, net in operating expense allocable to
our General Partner's minority interest in us(e)		23			24
Loss on sale of assets in operating costs and expenses (c)		4			14
Total segment gross operating margin	$	126,438		$	26,286

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 by EPCO" line item) of our Statements of Consolidated Cash Flows.
(e) This non-cash amount represents the minority interest'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 in our Statements of Consolidated Operations and Comprehensive Income to total segment gross operating margin (a non-GAAP financial measure):

	For the Three Months Ended March 31,
	2003		2002
Operating income (loss)	$	85,032	$	(1,233	)
Adjustments to reconcile operating income (loss)
to total segment gross operating margin:
Depreciation and amortization in operating costs and expenses		27,657		17,238
Operating lease expenses for which EPCO has retained the cash
payment obligation, net in operating costs and expenses		2,274		2,305
Loss on sale of assets in operating costs and expenses		4		14
Selling, general and administrative costs		11,471		7,962

Total segment gross operating margin	$	126,438	$	26,286

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

	Operating Segments
	Fractionation	Pipelines	Processing		Octane Enhancement		Other		Adjs. and Elims.		Consol. Totals
Revenues from third parties:
Three months ended March 31, 2003	$204,490	$ 201,893	$ 941,686				$ 713				$1,348,782
Three months ended March 31, 2002	103,799	75,844	391,131				472				571,246

Revenues from related parties:
Three months ended March 31, 2003	623	40,705	91,476								132,804
Three months ended March 31, 2002	5,623	23,237	61,903				45				90,808

Intersegment and intrasegment revenues:
Three months ended March 31, 2003	84,672	35,724	187,241				101		$(307,738	)
Three months ended March 31, 2002	33,397	24,510	126,260				100		(184,267	)

Total revenues:
Three months ended March 31, 2003	289,785	278,322	1,220,403				814		(307,738	)	1,481,586
Three months ended March 31, 2002	142,819	123,591	579,294				617		(184,267	)	662,054

Equity income in unconsolidated affiliates:
Three months ended March 31, 2003	284	4,778			$(3,441	)					1,621
Three months ended March 31, 2002	1,639	4,582			3,006						9,227

Gross operating margin by individual business segment and in total:
Three months ended March 31, 2003	29,047	71,932	29,956		(3,441	)	(1,056	)			126,438
Three months ended March 31, 2002	24,377	32,668	(33,376	)	3,006		(389	)			26,286

Segment assets:
At March 31, 2003	441,213	2,154,659	164,374				16,899		68,848		2,845,993
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 March 31, 2003	97,767	204,593	33,000		50,889						386,249
At December 31, 2002	95,467	213,632	33,000		54,894						396,993

Intangible Assets:
At March 31, 2003	70,439	7,837	195,796								274,072
At December 31, 2002	71,069	7,895	198,697								277,661

Goodwill:
At March 31, 2003 and
December 31, 2002	81,547										81,547

Our revenues are derived from a wide customer base. All consolidated revenues during the first quarter of 2003 and first quarter of 2002 were earned in the United States. Total consolidated revenues for the three months ended March 31, 2003 increased $819.5 million over those recorded during the same period in 2002. The majority of this increase is attributable to higher NGL prices, which (on a weighted-average basis for industry index prices) were 63 CPG during the first quarter of 2003 compared to 33 CPG during the first quarter of 2002. The higher NGL prices resulted in a significant increase in Processing segment revenues (particularly those of its NGL marketing activities component).

Also, higher natural gas prices during the first quarter of 2003 when compared to the first quarter of 2002 resulted in a substantial increase in Pipeline segment revenues from our Acadian Gas subsidiary. As part of its normal operations, Acadian Gas purchases natural gas from producers and suppliers and resells such natural gas to customers such as electric utility companies. The average index price for natural gas was $6.58 per MMBtu during the first quarter of 2003 versus $2.34 per MMBtu during the first quarter of 2002.

In addition to the effect of higher NGL and natural gas prices, consolidated revenues also increased as a result of acquisitions. Our Mid-America and Seminole pipeline systems contributed $82.5 million in revenues during the first three months of 2003.

Total segment gross operating margin was $126.4 million for the first quarter of 2003 compared to $26.3 million for the first quarter of 2002. The primary reasons for the increase are (i) the 2003 period includes $47.5 million of gross operating margin from Mid-America and Seminole (we acquired these operations in July 2002) and (ii) the 2002 period included $45.1 million in commodity hedging losses. 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.

Provision for income taxes is primarily applicable to the tax obligation of a consolidated subsidiary, Seminole Pipeline Company, which is a corporation and subject to income taxes. Seminole Pipeline Company became a consolidated subsidiary on August 1, 2002. The following is a summary of our provision for income taxes for the three months ended March 31, 2003:

Current:
Federal tax benefit	$	349
State tax benefit		47

		396

Deferred:
Federal		2,409
State		324

		2,733

Provision for income taxes	$	3,129

The following is a reconciliation of our provision for income taxes at the federal statutory rate to our recorded provision for income taxes:

Significant components of deferred income tax assets and liabilities at March 31, 2003 are as follows:


Deferred tax assets:
Property, plant and equipment	$	13,113
Deferred tax liabilities:
Other		(619	)

Net deferred tax assets	$	12,494

Based upon the periods in which taxable temporary differences are anticipated to reverse, we believe it is more likely than not that the Company will realize the benefits of these deductible differences. Accordingly, we believe that no valuation allowance is required for the deferred tax assets. However, the amount of the deferred tax asset considered realizable could be adjusted in the future if estimates of reversing taxable temporary differences are revised.

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 funds the purchase of the Units under the 1998 Plan at fair value in the open market. In general, our responsibility for reimbursing EPCO for the expense 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.

•

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.

•

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.

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 the market price of the Unit at the date of grant. Accordingly, no compensation expense related to Unit option grants is recognized in the Statements of Consolidated Operations and Comprehensive Income until the grants are exercised by the employee.

Accounting principles require us to illustrate the pro forma effect on our net income (loss) 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 March 31,
	2003			2002
Net income (loss):
As reported	$	40,505		$	(17,203	)
Additional Unit option-based compensation
expense estimated using the
fair value-based method		(171	)		(273	)

Pro forma	$	40,334		$	(17,476	)

Basic earnings per Unit:
As reported	$	0.20		$	(0.13	)
Pro forma	$	0.19		$	(0.13	)
Diluted earnings per Unit:
As reported	$	0.19		$	(0.13	)
Pro forma	$	0.18		$	(0.13	)

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 the 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 and Special Units outstanding during the period. In a period of net operating losses, the Special Units are excluded from the calculation of diluted earnings per Unit due to their antidilutive effect (as occurred for the first quarter of 2002). Treasury Units are not considered to be outstanding Units; therefore, they are excluded from the computation of both basic and diluted earnings per Unit. The amount of Common Units outstanding in the following table does not include Treasury Units.

The following table reconciles the number of Units used in the calculation of basic earnings per Unit and diluted earnings per Unit for the three months ended March 31, 2003 and 2002:

	For the Three Months Ended March 31,
	2003			2002
Income (loss) before minority interest	$	42,827		$	(17,376	)
General partner interest		(4,137	)		(1,246	)

Income (loss) before minority interest		38,690			(18,622	)
available to Limited Partners
Minority interest		(2,322	)		173

Net income (loss) available to Limited Partners	$	36,368		$	(18,449	)

BASIC EARNINGS PER UNIT
Numerator
Income(loss) before minority interest
available to Limited Partners	$	38,690		$	(18,622	)

Net income(loss)available
to Limited Partners	$	36,368		$	(18,449	)

Denominator
Common Units outstanding		154,076			102,706
Subordinated Units outstanding		32,115			42,820

Total		186,191			145,526

Basic Earnings per Unit
Income(loss) before minority interest
available to Limited Partners	$	0.21		$	(0.13	)

Net income(loss)available
to Limited Partners	$	0.20		$	(0.13	)

DILUTED EARNINGS PER UNIT
Numerator
Income(loss) before minority interest
available to Limited Partners	$	38,690		$	(18,622	)

Net income(loss)available
to Limited Partners	$	36,368		$	(18,449	)

Denominator
Common Units outstanding		154,076			102,706
Subordinated Units outstanding		32,115			42,820
Special Units outstanding		10,000			n/a

Total		196,191			145,526

Diluted Earnings per Unit
Income(loss) before minority interest
available to Limited Partners	$	0.20		$	(0.13	)

Net income(loss)available
to Limited Partners	$	0.19		$	(0.13	)

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

ASSETS	March 31, 2003			December 31, 2002
Current Assets
Cash and cash equivalents (includes restricted cash of $18,757 at
March 31, 2003 and $8,751 at December 31, 2002)	$	36,783		$	20,795
Accounts and notes receivable - trade, net of allowance for doubtful accounts of $21,249 at March 31, 2003 and $21,196 at December 31, 2002		482,965			399,187
Accounts receivable-affiliates		5,594			3,369
Inventories		101,962			167,369
Prepaid and other current assets		22,301			48,137

Total current assets		649,605			638,857
Property, Plant and Equipment, Net		2,845,993			2,810,839
Investments in and Advances to Unconsolidated Affiliates		386,249			396,993
Intangible assets, net of accumulated amortization of $29,136 at
March 31, 2003 and $25,546 at December 31, 2002		274,072			277,661
Goodwill		81,547			81,547
Deferred Tax Asset		13,113			15,846
Other Assets		16,305			9,818

Total	$	4,266,884		$	4,231,561

LIABILITIES AND PARTNERS' EQUITY
Current Liabilities
Current maturities of debt	$	15,000		$	15,000
Accounts payable - trade		74,364			67,283
Accounts payable - affiliates		35,162			40,773
Accrued gas payables		575,504			489,562
Accrued expenses		19,253			35,760
Accrued interest		17,974			30,338
Other current liabilities		23,997			42,644

Total current liabilities		761,254			721,360
Long-Term Debt		1,986,636			2,231,463
Other Long-Term Liabilities		7,663			7,666
Minority Interest		59,410			59,336
Commitments and Contingencies
Partners' Equity
Limited Partner		1,440,595			1,211,593
General Partner		14,700			12,363
Parent's Units acquired by Trust		(8,660	)		(8,660	)
Accumulated Other Comprehensive Income (Loss)		5,286			(3,560	)

Total Partners' Equity		1,451,921			1,211,736

Total	$	4,266,884		$	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 March 31,
	2003			2002
REVENUES
Revenues from consolidated operations
Third parties	$	1,348,782		$	571,246
Related parties		132,804			90,808

Total		1,481,586			662,054

COST AND EXPENSES
Operating costs and expenses
Third parties		1,152,302			518,049
Related parties		234,402			146,503
Selling, general and administrative
Third parties		4,808			1,833
Related parties		6,384			5,953

Total		1,397,896			672,338

EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES		1,621			9,227

OPERATING INCOME (LOSS)		85,311			(1,057	)

OTHER INCOME (EXPENSE)
Interest expense		(41,911	)		(18,513	)
Interest income from related parties					30
Dividend income from unconsolidated affiliates		2,601			954
Interest income - other		340			1,436
Other, net		36			52

Other income (expense)		(38,934	)		(16,041	)

INCOME (LOSS) BEFORE PROVISION FOR INCOME
TAXES AND MINORITY INTEREST		46,377			(17,098	)
PROVISION FOR INCOME TAXES		(3,129	)

INCOME (LOSS) BEFORE MINORITY INTEREST		43,248			(17,098	)
MINORITY INTEREST		(1,899	)		(53	)

NET INCOME (LOSS)		41,349			(17,151	)
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		(68	)

COMPREHENSIVE INCOME (LOSS)	$	50,195		$	(17,151	)

See Notes to Unaudited Consolidated Financial Statements

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

	For the Three Months Ended March 31,
	2003			2002
OPERATING ACTIVITIES
Net income (loss)	$	41,349		$	(17,151	)
Adjustments to reconcile net income (loss) to cash flows provided
by (used for) operating activities:
Depreciation and amortization in operating costs and expenses		27,657			17,238
Depreciation in selling, general and administrative costs		22			7
Amortization in interest expense		11,582			702
Equity in income of unconsolidated affiliates		(1,621	)		(9,227	)
Distributions received from unconsolidated affiliates		15,626			14,438
Operating lease expense paid by EPCO		2,274			2,305
Minority interest		1,899			53
Loss on sale of assets		4			14
Deferred income tax expense		2,733
Changes in fair market value of financial instruments		(28	)		30,141
Net effect of changes in operating accounts		47,767			(52,185	)

Operating activities cash flows		149,264			(13,665	)

INVESTING ACTIVITIES
Capital expenditures		(23,835	)		(17,112	)
Proceeds from sale of assets		34			10
Business acquisitions, net of cash received		(28,783	)		(368,631	)
Investments in and advances to unconsolidated affiliates		(20,509	)		(10,752	)

Investing activities cash flows		(73,093	)		(396,485	)

FINANCING ACTIVITIES
Borrowings under debt agreements		896,210			383,000
Repayments of debt		(1,141,000	)		(20,000	)
Debt issuance costs		(6,683	)
Distributions paid to partners		(70,454	)		(44,154	)
Distributions paid to minority interests		(1,806	)
Contributions from partners		258,170			39
Contributions from minority interests		26			10
Parent's Units acquired by consolidated Trust					(2,015	)
Settlement of treasury lock financial instruments		5,354
Increase in restricted cash		(10,006	)		(8,769	)

Financing activities cash flows		(70,189	)		308,111

NET CHANGE IN CASH AND CASH EQUIVALENTS		5,982			(102,039	)
CASH AND CASH EQUIVALENTS, JANUARY 1		12,044			132,071

CASH AND CASH EQUIVALENTS, MARCH 31	$	18,026		$	30,032

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		40,932			417									41,349
Leases paid by EPCO		2,251			23									2,274
Contributions from partners		255,562			2,608									258,170
Cash distributions to partners		(69,743	)		(711	)								(70,454	)
Reclassification of change in
value of treasury lock financial
instruments recorded as
cash flow hedges (see Note 11)											3,560			3,560
Cash gains on settlement of treasury
lock financial instruments
recorded as cash flow hedges (see Note 11)											5,354			5,354
Amortization of cash gains on
settlement of treasury lock
financial instruments to interest
expense in earnings (see Note 11)											(68	)		(68	)

Balances, March 31, 2003	$	1,440,595		$	14,700		$	(8,660	)	$	5,286		$	1,451,921

See Notes to Unaudited Consolidated Financial Statements

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 March 31, 2003 and consolidated results of operations and cash flows for the three months ended March 31, 2003 and 2002. 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 report on Form 10-Q.

The results of operations for the three months ended March 31, 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 terms are described within the glossary of this quarterly report on Form 10-Q.

See Note 14 for the pro forma effects to net income and earnings per Unit as if we had used the fair-value based method of accounting for Unit options.

The following recently issued accounting standards have been adopted and implemented by us:

•

SFAS No. 143, "Accounting for Asset Retirement Obligations";

•

SFAS No. 146, "Accounting for Costs Associated with Exit and Disposal Activities";

•

SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure"; and,

•

FIN No. 45, "Guarantor's Accounting and Disclosure Requirement from Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

We are currently evaluating the provisions of FIN No. 46, Consolidation of Variable Interest Entities.

SFAS No. 143. We adopted this standard as of January 1, 2003. This statement establishes accounting standards for the recognition and measurement of a liability for an asset retirement obligation (“ARO”) and the associated asset retirement cost. Under the provisions of this standard, we reviewed our long-lived assets for ARO liabilities and identified such liabilities in several operational areas. These include ARO liabilities related to (i) easements over property not currently owned by us and (ii) statutory regulatory requirements for abandonment or retirement of certain currently operated facilities.

Our preliminary allocation of the purchase price of each transaction is as follows:

	50% interest in EPIK			Port Neches Pipeline			Other		Total
Prepaid and other current assets	$	1,188		$	44				$	1,232
Property, plant and equipment		31,585			14,203			188		45,976
Investments in and advances to
unconsolidated affiliates		(17,247	)							(17,247	)
Accrued expenses		(1,102	)		(19	)				(1,121	)
Other current liabilities		(35	)		(24	)				(59	)
Minority interest								4		4

Total purchase price	$	14,389		$	14,204		$	192	$	28,785

Our inventories were as follows at the dates indicated:

	March 31, 2003		December 31, 2002
Working inventory	$	101,962	$	131,769
Forward-sales inventory				35,600

Inventory	$	101,962	$	167,369

Due to fluctuating market conditions in the midstream energy industry in which we operate, we occasionally recognize lower of average 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 months ended March 31, 2003 and 2002, we recognized $10.4 million and $0.1 million, respectively, of such LCM adjustments. The majority of these write-downs were taken against NGL inventories.

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

		March 31, 2003		December 31, 2002
Plants and pipelines	5-35	$	2,901,451	$	2,860,180
Underground and other storage facilities	5-35		284,214		283,114
Transportation equipment	3-35		5,223		5,118
Land			23,825		23,817
Construction in progress			68,848		49,586

Total			3,283,561		3,221,815
Less accumulated depreciation			437,568		410,976

Property, plant and equipment, net		$	2,845,993	$	2,810,839

Depreciation for the three-month periods ended March 31, 2003 and 2002 was $27.7 million and $17.2 million, respectively.

			March 31, 2003		December 31, 2002
Accounted for on equity basis:
Fractionation:
BRF	32.25	%	$	28,214	$	28,293
BRPC	30.00	%		17,392		17,616
Promix	33.33	%		41,049		41,643
La Porte	50.00	%		5,619		5,737
OTC	50.00	%		5,493		2,178
Pipeline:
EPIK (see Note 3)	50.00	%				11,114
Wilprise	37.35	%		8,508		8,566
Tri-States	33.33	%		25,571		25,552
Belle Rose	41.67	%		10,904		11,057
Dixie	19.88	%		37,461		36,660
Starfish	50.00	%		30,716		28,512
Neptune	25.67	%		76,928		77,365
Nemo	33.92	%		12,004		12,423
Evangeline	49.50	%		2,501		2,383
Octane Enhancement:
BEF	33.33	%		50,889		54,894
Accounted for on cost basis:
Processing:
VESCO	13.10	%		33,000		33,000

Total			$	386,249	$	396,993

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

	Ownership			For the Three Months Ended March 31,
	Percentage			2003			2002
Fractionation:
BRF		32.25	%	$	142		$	549
BRPC		30.00	%		148			249
Promix		33.33	%		260			1,043
La Porte		50.00	%		(181	)		(92	)
OTC		50.00	%		(85	)		(110	)
Pipelines:
EPIK (see Note 3)		50.00	%		1,818			1,683
Wilprise		37.35	%		163			147
Tri-States		33.33	%		549			469
Belle Rose		41.67	%		(29	)		74
Dixie		19.88	%		801			717
Starfish		50.00	%		1,149			812
Neptune		25.67	%		10			778
Nemo		33.92	%		336			(22	)
Evangeline		49.50	%		(19	)		(76	)
Octane Enhancement:
BEF		33.33	%		(3,441	)		3,006

Total				$	1,621		$	9,227

	Summarized Income Statement Information for the Three Months Ended
	March 31, 2003								March 31, 2002
	Revenues		Operating Inc (Loss)			Net Inc (Loss)			Revenues		Operating Income		Net Income
Pipelines	$	91,974	$	20,927		$	14,661		$	67,847	$	18,988	$	14,581
Fractionation		18,114		1,524			1,505			18,040		5,352		5,372
Octane Enhancement		45,651		(10,356	)		(10,322	)		47,929		8,978		9,019

The following table summarizes our excess cost information at March 31, 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		March 31, 2003		December 31, 2002
Fractionation		20-35 years		8,828				7,319		7,429
Pipelines		35 years (1)		41,943		9,246		47,338		47,637

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

Purchase of remaining 50% interest in EPIK

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

			At March 31, 2003					At December 31, 2002
	Gross Value		Accum. Amort.			Carrying Value		Accum. Amort.			Carrying Value
Shell natural gas processing agreement	$	206,216	$	(25,777	)	$	180,439	$	(23,015	)	$	183,201
Mont Belvieu Storage II contracts		8,127		(290	)		7,837		(232	)		7,895
Mont Belvieu Splitter III contracts		53,000		(1,767	)		51,233		(1,388	)		51,612
Toca-Western natural gas processing contracts		11,187		(466	)		10,721		(326	)		10,861
Toca-Western NGL fractionation contracts		20,042		(836	)		19,206		(585	)		19,457
Venice contracts (a)		4,636					4,636					4,635

Total	$	303,208	$	(29,136	)	$	274,072	$	(25,546	)	$	277,661


(a) Amortization scheduled to begin when contracted-volumes begin to be processed in late 2003

The following table shows amortization expense associated with our intangible assets for the three months ended March 31, 2003 and 2002:

	For the Three Months Ended March 31,
	2002		2003
Shell natural gas processing agreement	$	2,762	$	2,761
Mont Belvieu Storage II contracts		58		60
Mont Belvieu Splitter III contracts		379		252
Toca-Western natural gas processing contracts		140
Toca-Western NGL fractionation contracts		250

Total	$	3,589	$	3,073

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 March 31, 2003 and December 31, 2002):

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

	$	81,547

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

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

	March 31, 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	$	32,000			99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005		225,000			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		2,006,000			2,245,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt		1,712			1,774
Less unamortized discount on:
Senior Notes A		(71	)		(81	)
Senior Notes B		(222	)		(230	)
Senior Notes D		(5,783	)
Less current maturities of debt		(15,000	)		(15,000	)

Long-term debt	$	1,986,636		$	2,231,463

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. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 78.4% of its ownership interests). If we were to default on any guaranteed debt obligation, our Limited Partner would be responsible for full payment of that obligation.

New debt obligations issued during first quarter of 2003

During the first quarter of 2003, we completed the issuance of $850 million of private placement debt (Senior Notes C and D). Senior Notes C and D are unsecured obligations and rank equally with its existing and future unsecured and unsubordinated indebtedness and senior to any future subordinated indebtedness. Senior Notes C and D are guaranteed by the 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. 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

We entered into a $1.2 billion senior unsecured 364-day term loan to initially fund the acquisition of indirect interests in Mid-America and Seminole in July 2002. 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 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 by February 2003.

Covenants

We were in compliance with the various covenants of our debt agreements at March 31, 2003 and December 31, 2002.

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 three months ended March 31, 2003:

	Range of interest rates paid
364-Day Term Loan (a)	2.59% - 2.88%	2	.85%
364-Day Revolving Credit facility	2.47% - 4.25%	2	.52%
Multi-Year Revolving Credit facility	1.92% - 2.00%	1	.97%

(a) This facility was repaid in February 2003

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 our Amended and Restated Agreement of Limited Partnership dated July 31, 1998. 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 proceeds from this offering to repay a portion of the indebtedness outstanding under the 364-Day Term Loan. The remaining balance of proceeds was used for working capital purposes and offering expenses.

The net effect of changes in operating accounts and liabilities is as follows:

	For the Three Months Ended March 31,
	2003			2002
(Increase) decrease in:
Accounts and notes receivable	$	(86,002	)	$	794
Inventories		76,079			(31,748	)
Prepaid and other current assets		15,290			(2,494	)
Other assets		(503	)		(3,186	)
Increase (decrease) in:
Accounts payable		1,470			(13,369	)
Accrued gas payable		85,942			31,515
Accrued expenses		(17,628	)		(6,588	)
Accrued interest		(12,364	)		(16,137	)
Other current liabilities		(14,517	)		(10,891	)
Other liabilities					(81	)

Net effect of changes in operating accounts	$	47,767		$	(52,185	)

Commodity hedging financial instruments

During the first three months of 2002, we recognized a loss of $45.1 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 at the time 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.

Interest rate hedging financial instruments

We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. We define gross operating margin as operating income before: (1) depreciation and amortization amounts; (2) operating lease expenses for which the partnership does 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. Segment gross operating margin is derived by subtracting segment operating costs and expenses (before depreciation and amortization amounts, operating lease expenses for which the partnership does not have the payment obligation and gains and losses on the sale of assets) from segment revenues, with both segment totals before elimination of intercompany transactions. Intercompany accounts and transactions are eliminated in consolidation in accordance with GAAP. Segment gross operating margin is also exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. We have provided a reconciliation of total gross operating margin (a non-GAAP performance measure) to operating income.

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

	For the Three Months Ended March 31,
	2003			2002
Revenues (a)	$	1,481,586		$	662,054
Less operating costs and expenses (a)		(1,386,704	)		(664,552	)
Add equity in income of unconsolidated affiliates (b)		1,621			9,227

Subtotal		96,503			6,729
Add: Depreciation and amortization in operating costs and expenses (c)		27,657			17,238
Retained lease expense, net in operating expenses allocable to us (d)		2,274			2,305
Loss on sale of assets in operating costs and expenses(c)		4			14

Total segment gross operating margin	$	126,438		$	26,286


(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 by 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.

	For the Three Months Ended March 31,
	2003		2002
Operating income (loss)	$	85,311	$	(1,057	)
Adjustments to reconcile operating income (loss)
to total segment gross operating margin:
Depreciation and amortization in operating costs and expenses		27,657		17,238
Operating lease expenses for which EPCO has retained the cash
payment obligation, net in operating costs and expenses		2,274		2,305
Loss on sale of assets in operating costs and expenses		4		14
Selling, general and administrative costs		11,192		7,786

Total segment gross operating margin	$	126,438	$	26,286

Information by operating 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 March 31, 2003	$	204,490	$	201,893	$	941,686					$	713					$	1,348,782
Three months ended March 31, 2002		103,799		75,844		391,131						472						571,246
Revenues from
related parties:
Three months ended March 31, 2003		623		40,705		91,476												132,804
Three months ended March 31, 2002		5,623		23,237		61,903						45						90,808
Intersegment and intrasegment
revenues:
Three months ended March 31, 2003		84,672		35,724		187,241						101		$	(307,738	)
Three months ended March 31, 2002		33,397		24,510		126,260						100			(184,267	)
Total revenues:
Three months ended March 31, 2003		289,785		278,322		1,220,403						814			(307,738	)		1,481,586
Three months ended March 31, 2002		142,819		123,591		579,294						617			(184,267	)		662,054
Equity income in
unconsolidated affiliates:
Three months ended March 31, 2003		284		4,778				$	(3,441	)								1,621
Three months ended March 31, 2002		1,639		4,582					3,006									9,227
Gross operating margin by individual
business segment and in total:
Three months ended March 31, 2003		29,047		71,932		29,956			(3,441	)		(1,056	)					126,438
Three months ended March 31, 2004		24,377		32,668		(33,376	)		3,006			(389	)					26,286
Segment assets:
At March 31, 2003		441,213		2,154,659		164,374						16,899			68,848			2,845,993
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 March 31, 2003		97,767		204,593		33,000			50,889									386,249
At December 31, 2002		95,467		213,632		33,000			54,894									396,993
Intangible Assets:
At March 31, 2003		70,439		7,837		195,796												274,072
At December 31, 2002		71,069		7,895		198,697												277,661
Goodwill:
At March 31, 2003 and
December 31, 2002		81,547																81,547

Current:
Federal tax benefit	$	349
State tax benefit		47

		396

Deferred:
Federal		2,409
State		324

		2,733

Provision for income taxes	$	3,129

The following is a reconciliation of our provision for income taxes at the federal statutory rate to our recorded provision for income taxes:

Taxes computed by applying the federal statutory rate	$	2,888
State income taxes (net of federal benefit)		241

Provision for income taxes	$	3,129

Significant components of deferred income tax assets and liabilities at March 31, 2003 are as follows:

Deferred tax assets:
Property, plant and equipment	$	13,113
Deferred tax liabilities:
Other		(619	)

Net deferred tax assets	$	12,494

•

We pay EPCO for the costs attributable to equity-based awards granted to operations personnel it employs on our behalf.

•

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.

•

Accounting principles require us to illustrate the pro forma effect on our net income (loss) 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 March 31,
	2003			2002
Net income (loss):
As reported	$	41,349		$	(17,151	)
Additional Unit option-based compensation
expense estimated using the
fair value-based method		(171	)		(273	)

Pro forma	$	41,178		$	(17,424	)

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 in Part I of this quarterly report on Form 10-Q.

We have five reportable 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 interest in a facility that produces motor gasoline additives to enhance octane (currently producing MTBE). The Other operating segment consists of fee-based marketing services and various operational support activities.

We evaluate segment performance based on our measurement of gross operating margin (in the aggregate and by segment). This non-generally accepted accounting principle financial measure is used in this quarterly report. Amounts included in the calculation of this measure are computed in accordance with generally accepted accounting principles (“GAAP”). As part of our quarterly report, we have provided a reconciliation of this non-GAAP financial measure to its most comparable financial measure calculated and presented in accordance with GAAP.

We believe that investors benefit from having access to the same financial measures being utilized by management. Gross operating margin is an important performance measure of the economic success of our core operations and individual asset locations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among segments. The nearest GAAP counterpart to gross operating margin is operating income. Operating income, however, includes expense items that management does not consider when evaluating the core profitability of an operation such as depreciation and selling, general and administrative costs.

We define gross operating margin as operating income before: (1) depreciation and amortization amounts; (2) operating lease expenses for which the partnership does 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. Segment gross operating margin is derived by subtracting segment operating costs and expenses (before depreciation and amortization amounts, operating lease expenses for which the partnership does not have the payment obligation and gains and losses on the sale of assets) from segment revenues, with both segment totals before elimination of intercompany transactions. Intercompany accounts and transactions are eliminated in consolidation in accordance with GAAP. Segment gross operating margin is also exclusive of other income and expense transactions, provision for income taxes, minority interest and extraordinary charges. We have reconciled total gross operating margin (a non-GAAP performance measure) to 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 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, see footnote 12 of our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

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

	For the Three Months Ended March 31,
	2003		2002
Revenues	$	1,481,586	$	662,054
Operating costs and expenses		1,386,704		664,552
Selling, general and administrative costs		11,471		7,962
Equity in income of unconsolidated affiliates		1,621		9,227
Operating income (loss)		85,032		(1,233	)

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

	For the Three Months Ended March 31,
	2003		2002
Operating income (loss)	$	85,032	$	(1,233	)
Adjustments to reconcile operating income (loss)
to total segment gross operating margin:
Depreciation and amortization in operating costs and expenses		27,657		17,238
Operating lease expenses for which EPCO has retained the cash
payment obligation, net in operating costs and expenses		2,274		2,305
Loss on sale of assets in operating costs and expenses		4		14
Selling, general and administrative costs		11,471		7,962

Total segment gross operating margin	$	126,438	$	26,286

EPCO subleases certain equipment to us located at our Mont Belvieu facility and 100 railroad tankcars for $1 dollar per year. These subleases (the “retained leases”) 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, see “Related party transactions” on page 50 and “Capital spending” on page 49 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 March 31,
	2003			2002
Gross operating margin by segment:
Pipelines	$	71,932		$	32,668
Fractionation		29,047			24,377
Processing		29,956			(33,376	)
Octane enhancement		(3,441	)		3,006
Other		(1,056	)		(389	)

Gross operating margin total	$	126,438		$	26,286

Our significant plant production and other volumetric data were as follows for the periods indicated:

	For the Three Months Ended March 31,
	2003	2002
MBPD, Net
NGL and Petrochemical Pipelines	1,348	537
NGL Fractionation	240	204
Propylene Fractionation	61	52
Isomerization	80	74
Equity NGL Production	54	81
Octane Enhancement	3	4

BBtus per day, Net
Natural Gas Pipelines	1,055	1,224

Equivalent MBPD, Net
NGL, petrochemical and natural gas pipelines	1,626	859

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

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

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

2003
1st Quarter	$	6.58	$	34.07	$	0.43	$	0.65	$	0.76	$	0.80	$	0.24	$	0.21

(a) Natural , NGL, polymer grade propylene and refinery grade propylene prices represent an average of various
commercial index prices including OPIS and CMAI
(b) Crude Oil price is representative of the index price for West Texas Intermediate

Three months ended March 31, 2003 compared to three months ended March 31, 2002

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

Revenues for the three months ended March 31, 2003 increased $819.5 million over those recorded during the same period in 2002. The increase is primarily due to higher NGL, propylene and natural gas prices (see comparative product prices chart on page 42). The higher NGL prices resulted in a significant increase in Processing segment revenues (particularly those of its NGL marketing activities component). The higher propylene prices contributed to an increase in the revenues we derive from our petrochemical marketing activities. Also, the higher natural gas prices quarter-to-quarter resulted in an increase in Pipeline segment revenues from our Acadian Gas subsidiary. As part of its normal operations, Acadian Gas purchases natural gas from producers and suppliers and resells such natural gas to customers such as electric utility companies. Lastly, revenues increased as a result of acquisitions we completed since March 31, 2002 (particularly our acquisition of indirect interests in Mid-America and Seminole in July 2002).

Operating costs and expenses for the three months ended March 31, 2003 were $722.2 million higher than those recorded for the same period in 2002. The increase is primarily due to the same reasons that caused our revenues to be higher. As a result of the higher NGL, propylene and natural gas prices, the prices we paid for feedstocks and inventories increased. This affected our NGL and petrochemical marketing activities as well as our Acadian Gas natural gas purchases. In addition to the increase in product purchase prices, operating costs and expenses also increased as a result of acquisitions.

Our operating costs and expenses for the first three months of 2002 include a $45.1 million loss we recognized from our commodity hedging activities. In March 2002, the effectiveness of our primary commodity hedging strategy at the time 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 three months of 2003, we recorded a loss of $0.9 million from our commodity hedging activities.

Operating income was $85.0 million for the first three months of 2003 compared to a loss of $1.2 million for the first three months of 2002. Total gross operating margin was $126.4 million for the 2003 period versus $26.3 million for the 2002 period. The primary reasons for the increase in operating income and total gross operating margin are (i) the 2003 period includes results from our recently acquired Mid-America and Seminole pipeline systems and (ii) the 2002 period includes $45.1 million in commodity hedging losses. From a gross operating margin standpoint, Mid-America and Seminole contributed $47.5 million for the first quarter of 2003.

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

Pipelines. Gross operating margin from our Pipelines segment was $71.9 million for the first quarter of 2003 compared to $32.7 million for the first quarter of 2002. On an energy-equivalent basis, net pipeline throughput volume was 1,626 MBPD for the 2003 period versus 859 MBPD for the 2002 period. The increase in gross operating margin and throughput volume is primarily due to the acquisition of Mid-America and Seminole. These systems earned gross operating margin of $47.5 million on volumes of 816 MBPD for the first quarter of 2003. This acquisitions-related increase was offset by a decrease in gross operating margin from our Louisiana Pipeline System and our storage operations. Gross operating margin from our Louisiana Pipeline System declined $2.4 million quarter-to-quarter primarily due to lower throughput volumes attributable to a decrease in NGL extraction rates at regional gas processing facilities. Gross operating margin from our NGL and petrochemical storage operations was $4.7 million lower quarter-to-quarter as a result of higher storage well charges.

Fractionation. Gross operating margin from our Fractionation segment was $29.0 million for the first quarter of 2003 compared to $24.4 million for the first quarter of 2002. Gross operating margin from NGL fractionation improved $2.2 million quarter-to-quarter primarily due to an increase in in-kind fees at our Norco facility due to higher NGL prices. NGL fractionation volumes were 240 MBPD during the first three months of 2003 compared to 204 MBPD during the first three months of 2002. Gross operating margin from propylene fractionation declined $2.8 million quarter-to-quarter primarily due to higher energy-related costs, unscheduled

maintenance at one of our propylene fractionators and lower petrochemical marketing margins. Propylene fractionation volumes were 61 MBPD during the 2003 period versus 52 MBPD during the 2002 period. Gross operating margin from isomerization increased $3.6 million quarter-to-quarter primarily due to higher volumes and NGL by-product revenues. Isomerization volumes increased to 80 MBPD during the 2003 period from 74 MBPD during the 2002 period. Gross operating margin for our Fractionation segment also includes a one-time benefit of $1.1 million resulting from the settlement of a business interruption and related insurance claims involving Fractionation segment assets used to support our BEF investment.

Processing. Gross operating margin from our Processing segment was $30.0 million for the first quarter of 2003 compared to a loss of $33.4 million for the first quarter of 2002. As noted under our discussion of operating costs and expenses on page 43, the 2002 period includes commodity hedging losses of $45.1 million. Our commodity hedging results for the first quarter of 2003 were negligible. During the first quarter of 2003, our NGL marketing activities benefited from higher NGL prices and strong demand for propane and normal butane. This more than offset the decrease in gross operating margin caused by a decrease in equity NGL production from 81 MBPD during the 2002 period to 54 MBPD in the 2003 period.

The decrease in equity NGL production was largely attributable to higher natural gas prices relative to NGL prices, which caused us to minimize the amount of NGLs that were extracted by our natural gas processing facilities. In order to meet the natural gas processing needs of Shell (our largest processing customer) in this difficult pricing 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, see our discussion entitled “Related party transactions” on page 50.

Octane enhancement. Our equity earnings from BEF were a loss of $3.4 million for the first quarter of 2003 compared to income of $3.0 million for the first quarter of 2002. The quarter-to-quarter decline in equity earnings is attributable to increased downtime related to maintenance activities (which contributed to higher maintenance expenses); lower MTBE sales margins (primarily due to high methanol feedstock prices); and MTBE inventory valuation adjustments. BEF’s gross MTBE production rate declined to 10.1 MBPD during the first quarter of 2003 from 13.5 MBPD during the first quarter of 2002. We held a 33.3% ownership interest in BEF during both periods.

Selling, general and administrative expenses. These expenses were $11.5 million for the first quarter of 2003 versus $8.0 million for the first quarter of 2002. The increase is primarily due to the additional staff and resources needed to support our expansion activities resulting from acquisitions and other business development. The 2003 period includes a $2.0 million payment we made to Williams for general and administrative transition services related to our acquisition of the Mid-America and Seminole pipelines. These payments ceased in February 2003 when we took over the operation of these two systems.

Interest expense. Interest expense increased to $41.9 million for the first quarter of 2003 from $18.5 for the first quarter of 2002. The increase is primarily due to debt obligations we incurred as a result of business acquisitions, particularly the $1.2 billion in overall financing used to purchase Mid-America and Seminole in July 2002.

Interest expense for the 2003 period includes a non-cash charge of $11.3 million related to unamortized costs associated with the 364-Day Term Loan that we used to initially fund the Mid-America and Seminole acquisitions. In February 2003, we completely repaid this loan. As a result, all unamortized costs associated with this debt was charged to expense. For more information regarding our debt obligations and changes since December 31, 2002, please see “Our liquidity and capital resources – Our debt obligations”.

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 fair values 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 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 businesses, see “Cautionary Statement regarding Forward-Looking Information and Risk Factors” on page 56 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 March 31, 2003, we had approximately $2.0 billion outstanding under various debt agreements. On that date, total borrowing capacity under our revolving commercial bank credit facilities was $500 million of which $217.3 million of capacity was available. For additional information regarding our debt, see “Our debt obligations” on page 48.

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 9.8 million 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 14.7 million 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 $850 million of private placement debt (Senior Notes C and D). For information regarding our application of cash generated by these debt offerings, please read the section titled “Our debt obligations” within this “Our liquidity and capital resources” discussion.

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 accordance with Rule 457(p) promulgated under the Securities Act of 1933, as amended, the registration fee associated with the unsold portion of the securities under the shelf registration statement filed in February 2001 was used to offset the registration fee due in connection with our $1.5 billion universal shelf registration statement. When our new shelf registration was declared effective by the SEC in April 2003, the securities remaining under the shelf registration statement filed in February 2001 were deemed deregistered.

We have the ability to issue an unlimited number of Common Units to finance acquisitions and capital improvements if Adjusted Operating Surplus (as defined within our partnership agreement) for each of the four fiscal quarters immediately preceding the expenditure, on a pro forma basis, would have increased as a result of such expenditure (i.e., would have been accretive on a pro forma basis for each of the quarters in the test). For those

acquisitions and other transactions that do not qualify under the aforementioned pro forma “accretive” test, we have 54,550,000 Units available for general partnership purposes during the Subordination Period. The Subordination Period generally extends until the first day of any quarter beginning after June 30, 2003 when certain financial tests have been satisfied. We expect the Subordination Period to end on August 1, 2003. After the Subordination Period expires, we may prudently issue an unlimited number of Units for general partnership purposes that do not meet the pro forma “accretive” test.

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.

Three months ended March 31, 2003 compared to three months ended March 31, 2002

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

Operating cash flows. Cash flow from operating activities was an inflow of $151.6 million during the first quarter of 2003 compared to an outflow of $10.0 million during the first quarter of 2002. The following table summarizes the major components of operating cash flows for first three months of 2003 and 2002 (dollars in thousands):

	For the Three Months Ended March 31,
	2003			2002
Net income (loss)	$	40,505		$	(17,203	)
Adjustments to reconcile net income (loss) to cash flows provided by
(used for) operating activities before changes in operating accounts:
Depreciation and amortization		39,261			17,947
Equity in income of unconsolidated affiliates		(1,621	)		(9,227	)
Distributions received from unconsolidated affiliates		15,626			14,438
Changes in fair market value of financial instruments		(28	)		30,141
Other		7,309			2,122

Cash flow from operating activities before changes in operating accounts	$	101,052		$	38,218
Net effect of changes in operating accounts		50,497			(48,191	)

Operating activities cash flows	$	151,549		$	(9,973	)

As shown in the table above, cash flow before changes in operating accounts was an inflow of $101.1 million during the first quarter of 2003 versus $38.2 million during the same period in 2002. We believe that cash flow from operating activities before changes in operating accounts is an important measure of our liquidity. We believe it provides an indication of our ability to generate core cash flows from the assets and investments we own or in which we have an interest. The $62.9 million increase in this element of our operating 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 $45.1 million of commodity hedging losses versus practically none 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 $21.3 million increase in depreciation and amortization is primarily due to businesses we acquired since the first quarter of 2002. Changes in operating accounts are 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 see footnote 10 in our Notes to Unaudited Consolidated Financial Statements included under Item 1 of this quarterly report.

Investing cash flows. During the first three months of 2003, we used $73.1 million in cash for investing activities compared to $396.5 million during the same period for 2002. We used $28.8 million and $368.6 million for business acquisitions during the first quarter of 2003 and 2002, respectively. The 2003 period includes our acquisition of the Port Neches Pipeline and the remaining 50% ownership interests in EPIK. The 2002 period includes our acquisition of Diamond-Koch’s Mont Belvieu NGL and petrochemical storage business and propylene fractionation business.

Our capital expenditures were $23.8 million during the first quarter of 2003 and $17.1 million during the first quarter of 2002. The majority of the expenditures for the 2003 period related to Processing segment projects whereas the expenditures for the 2002 period centered on Pipeline segment projects. In addition, we made investments in and advances to our unconsolidated affiliates of $20.5 million during the first quarter of 2003 compared to $10.8 million during the first quarter of 2002. The increase is primarily due to funding our share of the expansion projects of our Gulf of Mexico natural gas pipeline investments.

Financing cash flows. Our financing activities were a cash outflow of $69.7 million during the first quarter of 2003 versus a cash inflow of $304.4 million during the first quarter of 2002. During the 2003 period, we made net payments on our debt obligations of $244.8 million with the aid of $258.2 million from our January 2003 equity offering. 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 reflects the borrowings under our revolving bank credit facilities primarily to fund the acquisition of Diamond-Koch’s propylene fractionation business. Cash distributions to our partners increased to $69.2 million during the first quarter of 2003 from $47.4 million during the first quarter of 2002 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:

	March 31, 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	$	32,000			99,000
Multi-Year Revolving Credit facility, variable rate,
due November 2005		225,000			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		2,006,000			2,245,000
Unamortized balance of increase in fair value related to
hedging a portion of fixed-rate debt		1,712			1,774
Less unamortized discount on:
Senior Notes A		(71	)		(81	)
Senior Notes B		(222	)		(230	)
Senior Notes D		(5,783	)
Less current maturities of debt		(15,000	)		(15,000	)

Long-term debt	$	1,986,636		$	2,231,463

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

New debt obligations issued during first quarter of 2003

incurred to finance the Mid-America and Seminole acquisitions. In April 2003, we initiated an offer to exchange the private placement Senior Notes C for publicly-registered Senior Notes C.

Repayment of 364-Day Term Loan

Our Operating Partnership entered into a $1.2 billion senior unsecured 364-day term loan to initially fund the acquisition of indirect interests in Mid-America and Seminole in July 2002. We used $178.5 million of the $182.5 million in proceeds from our October 2002 equity offering to partially repay this loan. We 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 by February 2003.

Covenants

We were in compliance with the various covenants of our debt agreements at March 31, 2003 and December 31, 2002.

Credit ratings

Our current investment grade credit ratings are Baa2 by Moody’s Investor Service and BBB by Standard and Poors. Upon our acquisitions of the Mid-America and Seminole pipelines, both agencies maintained our ratings; however, each placed us on negative outlook pending the issuance of an appropriate amount of equity to repay the debt we incurred to fund these acquisitions. The agencies have responded positively to our recent equity and debt offerings. 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

At March 31, 2003, we had $11.1 million in estimated outstanding purchase commitments attributable to capital projects. Of this amount, $7.8 million is related to the construction of assets that will be recorded as property, plant and equipment and $3.3 million is associated with our share of capital projects of our unconsolidated affiliates which will be recorded as additional investments in unconsolidated affiliates.

During the remainder of 2003, we expect capital spending on internal growth projects to approximate $105.9 million, of which $44.5 million is forecasted for various projects within our Pipelines segment; $35.7 million for the expansion of our Norco NGL fractionator and $13.3 million for the expansion of our Neptune gas processing facility. Our unconsolidated affiliates forecast a combined $35.1 million in capital expenditures during the remainder of 2003, the majority of which relate to expansion projects on our Gulf of Mexico natural gas pipeline systems. Our share of these forecasted capital expenditures is estimated at $15.1 million.

EPCO subleases to us all of the equipment it holds pursuant to operating leases relating to an isomerization unit, a deisobutanizer tower, two cogeneration units 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.

With regards to our material contractual obligations, there have been no significant changes outside of the ordinary course of our 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 the debt and equity offerings we completed during the first quarter of 2003 (which include 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.

•

Our letters of credit increased from $2.4 million at December 31, 2002 to $25.7 million at March 31, 2003. The increase is attributable to letter of credit requirements related to our import of NGL cargoes during the period.

The following table summarizes our updated material contractual obligations related to our debt obligations:

Contractual Obligations	Total		2003		2004 through 2005		After 2007
Principal payments to be made
under debt obligations	$	2,006,000	$	15,000	$	637,000	$	1,354,000
Potential payments due under
letter of credit agreements	$	25,695			$	25,695

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, Chairman and a director (and Chairman of the Board of Directors) of the 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 our General Partner is to act as our managing partner. Collectively, EPCO and its affiliates owned 57.4% of our limited partnership interests and 70.0% of our General Partner at March 31, 2003.

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 employees who manage our business and affairs.

EPCO is also the operator of certain facilities we own or have an equity interest in. We have also entered into an agreement with EPCO to provide trucking services to us for 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 March 31,
	2003		2002
Revenues from consolidated operations	$	563	$	2,299
Operating costs and expenses		46,205		19,929
Selling, general and administrative expenses		6,384		5,953

Relationship with Shell

We have a commercial relationship with Shell as a partner, customer and vendor. At March 31, 2003, Shell owned approximately 20.1% of our limited partnership interests and 30.0% of our General Partner. Currently, three members of the Board of Directors of the General Partner (J.A. Berget, J.R. Eagan and A.Y. Noojin, III) are employees of Shell.

Shell and its affiliates are the Company’s single largest customer. During the three months ended March 31, 2003 and 2002, they accounted for 5.5% and 8.7%, respectively, of our consolidated revenues. Our revenues from Shell 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, keepwhole Shell processing agreement, which grants us the right to process Shell’s current and future production from 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 20 years. This contract was amended effective March 1, 2003. Generally, the amended contract has 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 the mixed NGL stream is extracted.

In our natural gas processing activities under this contract, we reimburse Shell for the energy value of (i) the NGLs we extract and (ii) the natural gas we consume as fuel. This energy value is referred to as plant thermal reduction (“PTR”) and is based on the Btu content of the natural gas taken out of the stream. 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 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 probability of which we believe is low), 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 choose not to process) 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 March 31,
	2003		2002
Revenues from consolidated operations	$	82,220	$	57,657
Operating costs and expenses		171,714		105,148

Shell is also a partner with us in the Gulf of Mexico natural gas pipelines we acquired from El Paso in 2001. We also lease from Shell its 45.4% interest in our Splitter I propylene fractionation facility.

The following recently issued accounting standards have been adopted and implemented by us:

•

SFAS No. 143, "Accounting for Asset Retirement Obligations";

•

SFAS No. 146, "Accounting for Costs Associated with Exit and Disposal Activities";

•

SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure"; and,

•

FIN No. 45, "Guarantor's Accounting and Disclosure Requirement from Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

We are currently evaluating the provisions of FIN No. 46, Consolidation of Variable Interest Entities.

As a result of our analysis of the identified AROs, we were not required to recognize such potential liabilities. Our rights to the easements are renewable and only require retirement action upon nonrenewal of the easement agreements. We currently plan to renew all such easement agreements and use these properties indefinitely. Therefore, the ARO liability is not estimable for such easements. If we decide not to renew these agreements, an ARO liability would be recorded at that time. ARO liabilities related to statutory regulatory requirements for abandonment or retirement of certain currently operated facilities were also identified. 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 occurred. Certain Gulf of Mexico natural gas pipelines, in which we have an equity interest, have identified ARO’s relating to regulatory requirements. There is no current intention to abandon or retire these pipelines. If these pipelines were abandoned or retired, an ARO liability would then be disclosed.

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 the 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.

There have been no significant changes in our critical accounting policies since December 31, 2002. For a detailed discussion of these policies, please see the section titled “Our critical accounting policies” under Item 7 of our annual report on Form 10-K 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. Additionally, if we determine that an asset’s undepreciated cost may not be recoverable due to impairment, this would result in a charge against earnings.

At March 31, 2003 and December 31, 2002, the net book value of our property, plant and equipment was $2.8 billion. See footnote 5 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our property, plant and equipment.

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 March 31, 2003 and December 31, 2002, the net book value of our intangible assets was $274.1 million and $277.7 million. See footnote 7 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our intangible assets.

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 March 31, 2003 and December 31, 2002, the carrying value of our goodwill was $81.5 million. See footnote 7 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our goodwill.

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 required under GAAP 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 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 three months of 2002, we recognized a loss of $45.1 million from our commodity hedging activities. Of this loss, $28.7 million was attributable to the change in fair value of the portfolio between December

31, 2001 and March 31, 2002. The fair value of open positions at March 31, 2002 was a payable of $23.1 million. 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.

During the first three months of 2003, we entered into a limited number of commodity financial instruments from which we recorded a loss of $0.9 million. The fair value of open positions at March 31, 2003 was a receivable of approximately $2 thousand. See footnote 11 of the Notes to Unaudited Consolidated Financial Statements for additional information regarding our financial instruments.

Uncertainties regarding our investment in BEF

In recent years, MTBE has been detected in municipal and private water supplies resulting in various legal actions. BEF has not been named in any MTBE legal action to date. In light of these developments, we and the other two partners of BEF are formulating a plan for the BEF facility if MTBE is banned. We are evaluating a possible conversion of the facility from MTBE production to alkylate production. The carrying value of our investment in BEF was $50.9 million at March 31, 2003.

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 the Company satisfying certain financial tests. The remaining 21,409,872 Subordinated Units are anticipated to convert to Common Units on August 1, 2003. These conversions will 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.

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 review our “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.

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 (see the following discussion titled “Interest rate-related financial instruments portfolio”). For additional information regarding our financial instruments, see footnote 11 of our Notes to Unaudited Consolidated Financial Statements.

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 March 31, 2003, the net fair value of this portfolio was a receivable $2 thousand. We continue to have only a limited number of commodity financial instruments outstanding.

During the first three months of 2002, we recognized a loss of $45.1 million from our Processing segment’s commodity hedging activities that was recorded as an operating cost in our Statements of Consolidated Operations. In March 2002, the effectiveness of our primary commodity hedging strategy at the time 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 three months of 2003, we recorded a loss of $0.9 million from our commodity hedging activities, of which $0.1 million is attributable to the Processing segment and the remainder to Pipelines.

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 March 31, 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 transactions 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 these 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 (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our liquidity and capital resources—Our debt obligations” under Item 2 of this quarterly report). The settlement of the treasury locks resulted in our receipt of $5.4 million of 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 net $3.6 million net liability was recorded as a component of comprehensive income on that date, with no impact to current earnings. With the 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 to earnings. For additional information regarding our treasury lock transactions, see our footnote 11 of our Notes to Unaudited Consolidated Financial Statements.

In the 90-day period before the filing of this quarterly 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. These disclosure controls and procedures are those controls and other procedures we maintain, which are designed to insure 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 ensure 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.

Subsequent to the date when the disclosure controls and procedures were evaluated, there have not been any significant changes in the registrants’ controls or procedures or in other factors that could significantly affect such controls or procedures. No significant deficiencies or material weaknesses were detected, so no corrective actions needed to be taken.

(a)(1) and (2) Financial Statements and Financial Statement Schedules.

See “Index to Financial Statements” set forth on page F-1.

(a)(3) 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 the 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 the General Partner 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 Multi-Year Revolving Credit Facility dated effective as of November 15, 2002 (incorporated by reference to Exhibit 4.21 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).
10.1**	--	Sixth Amendment to Conveyance of Gas Processing Rights, dated as of March 1, 2003 among Enterprise Gas Processing, LLC, Shell Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Consolidated Energy Resources Inc., Shell Land & Energy Company, Shell Frontier Oil & Gas Inc. and Shell Gulf of Mexico Inc. (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 9, 2003).
10.2	--	Letter agreement dated April 9, 2003, relating to Sixth Amendment to Conveyance of Gas Processing Rights related to Exhibit 10.14 to this report (incorporated by reference to Exhibit 10.2 to Form 8-K filed May 9, 2003).
99.1#	--	Section 1350 Certifications

*	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.
**	Portions of this Exhibit have been omitted pursuant to a request for confidential treatment.
#	Filed with this report.

(b) Reports on Form 8-K.

January 10, 2003 filing, Item 5. On January 9, 2003, we entered into an underwriting agreement for the public offering of 12,750,000 Common Units, including 1,000,000 Common Units to be offered to four trusts established for the benefit of the children of Dan L. Duncan, the Chairman of the Board of our General Partner. Closing of the issuance and sale of the Common Units occurred on January 15, 2003.

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 May 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

CERTIFICATION OF O.S. ANDRAS, PRINCIPAL EXECUTIVE OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS PARTNERS L.P.

I, O.S. Andras, the Principal Executive Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Partners L.P., certify that:

I have reviewed this quarterly report on Form 10-Q of Enterprise Products Partners L.P.;

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-13 and 15d-14) for the registrant and we have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and audit committee of registrant’s board of directors (or persons performing the equivalent function):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 13, 2003

		/s/ O.S. Andras
		Name: O.S. Andras
		Title: Principal Executive Officer of our General Partner, Enterprise Products GP, LLC

CERTIFICATION OF MICHAEL A. CREEL, PRINCIPAL FINANCIAL OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS PARTNERS L.P.

I, Michael A. Creel, the Principal Financial Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Partners L.P., certify that:

I have reviewed this quarterly report on Form 10-Q of Enterprise Products Partners L.P.;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: May 13, 2003

		/s/ Michael A. Creel
		Name: Michael A. Creel
		Title: Principal Financial Officer of our General Partner, Enterprise Products GP, LLC

CERTIFICATION OF O.S. ANDRAS, PRINCIPAL EXECUTIVE OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS OPERATING L.P.

I, O.S. Andras, the Principal Executive Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Operating L.P., certify that:

I have reviewed this quarterly report on Form 10-Q of Enterprise Products Operating L.P.;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: May 13, 2003

		/s/ O.S. Andras
		Name: O.S. Andras
		Title: Principal Executive Officer of our General Partner, Enterprise Products GP, LLC

CERTIFICATION OF MICHAEL A. CREEL, PRINCIPAL FINANCIAL OFFICER OF
ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS OPERATING L.P.

I, Michael A. Creel, the Principal Financial Officer of Enterprise Products GP, LLC, the General Partner of Enterprise Products Operating L.P., certify that:

I have reviewed this quarterly report on Form 10-Q of Enterprise Products Operating L.P.;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: May 13, 2003

		/s/ Michael A. Creel
		Name: Michael A. Creel
		Title: Principal Financial Officer of our General Partner, Enterprise Products GP, LLC

EXHIBIT 99.1

CERTIFICATION OF O.S. ANDRAS, CHIEF EXECUTIVE OFFICER
OF ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS OPERATING L.P. AND ENTERPRISE PRODUCTS PARTNERS L.P.

In connection with this combined quarterly report of Enterprise Products Partners L.P. and Enterprise Products Operating L.P. (collectively, the “Registrants”) on Form 10-Q for the three months ending March 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, O.S. Andras, Chief Executive Officer of Enterprise Products GP, LLC, the General Partner of the Registrants, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrants.

/s/ O.S. Andras

Name: O.S. Andras

Title:       Chief Executive Officer of Enterprise Products GP, LLC
                on behalf of Enterprise Products Operating L.P. and
                Enterprise Products Partners L.P.

Date: May 13, 2003

A signed original of this written statement required by Section 906 has been provided to the Registrants and will be retained by the Registrants and furnished to Securities and Exchange Commission or its staff upon request.

CERTIFICATION OF MICHAEL A. CREEL, CHIEF FINANCIAL OFFICER
OF ENTERPRISE PRODUCTS GP, LLC THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS OPERATING L.P. AND ENTERPRISE PRODUCTS PARTNERS L.P.

In connection with the combined quarterly report of Enterprise Products Partners L.P. and Enterprise Products Operating L.P. (collectively, the “Registrants”) on Form 10-Q for the three months ending March 31, 2003 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael A. Creel, Chief Financial Officer of Enterprise Products GP, LLC, the General Partner of the Registrants, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrants.

/s/ Michael A. Creel

Name: Michael A. Creel

Title:       Chief Financial Officer of Enterprise Products GP, LLC
                on behalf of Enterprise Products Operating L.P. and
                 Enterprise Products Partners L.P.

Date: May 13, 2003

Mont Belvieu Splitter III acquisition

MBA acquisition

ENTERPRISE PRODUCTS OPERATING L P 10-Q