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

FORM 8-K

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

Date of Report (Date of earliest event reported): December 31, 2004

ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact Name of Registrant as Specified in Its Charter)

Delaware	1-14323	76-0568219
(State or Other Jurisdiction of Incorporation or Organization)	(Commission File Number)	(I.R.S. Employer Identification No.)

	2727 North Loop West, Houston, Texas	77008-1044
	(Address of Principal Executive Offices)	(Zip Code)

(713) 880-6500
(Registrant’s Telephone Number, including Area Code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 8.01.

OTHER EVENTS.

1.	Update to Form S-3 Registration Statement

On March 23, 2005, a Registration Statement on Form S-3 (the “Registration Statement”) of Enterprise Products Partners L.P. and Enterprise Products Operating L.P. (Reg. No. 333-123150) was declared effective by the Securities and Exchange Commission. Enterprise Products Partners L.P. hereby incorporates by reference into the prospectus included in the Registration Statement the following information:

EXPERTS

The (1) consolidated financial statements and the related consolidated financial statement schedule of Enterprise Products Partners L.P. and subsidiaries as incorporated in this prospectus, by reference from Enterprise Products Partners L.P.’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission on March 15, 2005, and (2) the balance sheet of Enterprise Products GP, LLC as of December 31, 2004, incorporated in this prospectus by reference from Enterprise Products Partners L.P.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 31, 2005, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports, which are incorporated herein by reference (each such report expresses an unqualified opinion), and have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

2.	Enterprise General Partner Balance Sheet (Audited)

The following is the audited consolidated balance sheet of Enterprise Products GP, LLC at December 31, 2004. Enterprise Products GP, LLC is the general partner of Enterprise Products Partners L.P.

ENTERPRISE PRODUCTS GP, LLC

TABLE OF CONTENTS

Independent Auditors’ Report

Consolidated Balance Sheet at December 31, 2004

Notes to Consolidated Balance Sheet
	Note 1 - Organization and consolidation		4
	Note 2 - Summary of significant accounting policies		5
	Note 3 - Recent accounting developments		8
	Note 4 - Business combinations		9
	Note 5 - Inventories	13
	Note 6 - Property, plant and equipment	14
	Note 7 - Investments in and advances to unconsolidated affiliates	15
	Note 8 - Intangible assets and goodwill	20
	Note 9 - Debt obligations	23
	Note 10 - Minority interest	29
	Note 11 - Capital structure	30
	Note 12 - Related party transactions	30
	Note 13 - Commitments and contingencies	33
	Note 14 - Financial instruments	36
	Note 15 - Segment information	39
	Note 16 - Condensed financial information of Operating Partnership	41
	Note 17 - Subsequent events	42

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors of Enterprise Products GP, LLC

Houston, Texas

We have audited the accompanying consolidated balance sheet of Enterprise Products GP, LLC (the “Company”) at December 31, 2004. This consolidated financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this consolidated financial statement based on our audit.

We conducted our audit in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated balance sheet presents fairly, in all material respects, the financial position of the Company at December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 31, 2005

ENTERPRISE PRODUCTS GP, LLC

CONSOLIDATED BALANCE SHEET

AT DECEMBER 31, 2004

(Dollars in thousands)

ASSETS
Current Assets
	Cash and cash equivalents (includes restricted cash of $26,157)			$ 51,163
	Accounts and notes receivable - trade, net of allowance for doubtful accounts
		of $24,310		1,058,375
	Accounts receivable - related parties			25,151
	Inventories			189,019
	Assets held for sale			36,562
	Prepaid and other current assets			80,893
			Total current assets	1,441,163
Property, Plant and Equipment, net				7,831,467
Investments in and Advances to Unconsolidated Affiliates				519,164
Intangible Assets, net of accumulated amortization of $74,183				980,601
Goodwill				459,198
Deferred Tax Asset				6,467
Long-term Receivables				14,931
Other Assets				62,910
			Total	$ 11,315,901

LIABILITIES AND MEMBERS' EQUITY
Current Liabilities
	Current maturities of debt			$ 18,450
	Accounts payable – trade			203,144
	Accounts payable - related parties			41,293
	Accrued gas payables			1,021,294
	Accrued expenses			130,051
	Accrued interest			73,151
	Other current liabilities			104,979
			Total current liabilities	1,592,362
Long-Term Debt				4,629,219
Other Long-Term Liabilities				63,739
Minority Interest				4,865,698
Commitments and Contingencies
Members' Equity				164,883
			Total	$ 11,315,901

See Notes to Consolidated Balance Sheet.

ENTERPRISE PRODUCTS GP, LLC

NOTES TO CONSOLIDATED BALANCE SHEET

AT DECEMBER 31, 2004

1. ORGANIZATION AND CONSOLIDATION

ENTERPRISE PRODUCTS GP, LLC (“EPGP”) is a Delaware limited liability company formed in May 1998 that is the general partner of Enterprise Products Partners L.P. EPGP's primary business purpose is to manage the affairs and operations of Enterprise Products Partners, L.P. and its subsidiaries (collectively referred to as “EPD”). EPD is a publicly traded Delaware limited partnership listed on the New York Stock Exchange (“NYSE”) under symbol “EPD.” EPD conducts substantially all of its business through its wholly owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”). EPD and the Operating Partnership were formed to acquire, own and operate the natural gas liquids (“NGL”) business of EPCO, Inc. (“EPCO”).

Unless the context requires otherwise, references to “we”, “us”, “our”, “EPGP” or the “Company” within these notes shall mean EPGP and its consolidated subsidiaries, which include EPD and its subsidiaries. References to “Shell” shall mean Shell Oil Company, its subsidiaries and affiliates. References to “El Paso” shall mean El Paso Corporation and its affiliates.

At December 31, 2004, Duncan Family Interests, Inc. (“DFI”) owned 85.6%, Dan Duncan, LLC (“DDC”) owned 4.5% and El Paso owned 9.9% of the membership interests of EPGP. DFI, DDC and El Paso are collectively referred to as the “Members.” EPCO is the ultimate parent of DFI and an affiliate of DDC. In January 2005, an affiliate of EPCO, purchased El Paso's 9.9% membership interest in us. See Note 17 for additional information regarding this subsequent event.

On September 30, 2004, we completed the GulfTerra Merger. For additional information regarding this event, please see Note 4.

We own a 2% general partner interest in EPD, which conducts substantially all of our business. We have no independent operations and no material assets outside those of EPD. The number of reconciling items between our consolidated balance sheet and that of EPD are few. The most significant is that relating to minority interest in our net assets by the limited partners of EPD and the elimination of our investment in EPD with our underlying partner’s capital account in EPD. See Note 10 for additional details of minority interest in our consolidated subsidiaries.

As a result of DFI acquiring Shell’s 30% member interest in EPGP on September 12, 2003, the financial statements of EPD were consolidated with those of EPGP beginning in September 2003. This accounting consolidation is required because Shell’s minority interest rights in EPGP (which gave them significant participating rights) were terminated as a result of the purchase. This fact, along with DFI’s indirect control of EPD through its common unit holdings, gives EPGP the ability to exercise control over EPD. All intercompany accounts and transactions have been eliminated in consolidation.

The consolidated balance sheet includes our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after elimination of all material intercompany accounts and transactions. The majority-owned subsidiaries are identified based upon the determination that we possess a controlling financial interest through direct or indirect ownership of a majority voting interest in the subsidiary. Investments in which we own 20% to 50% and exercise significant influence over operating and financial policies are accounted for using the equity method. Investments in which we own less than 20% are accounted for using the cost method unless we exercise significant influence over operating and financial policies of the investee, in which case the investment is accounted for using the equity method.

As a result of recently issued accounting guidance under EITF 03-16, the minimum ownership requirement for an investment organized as a limited liability company ("LLC") to qualify for the equity method of accounting was lowered to between 3% and 5% from the 20% threshold applied to other types of investments. On July 1, 2004, we changed our method of accounting for VESCO from the cost method to the equity method in accordance with EITF 03-16. For additional information regarding this change in accounting method, see Note 7.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The following is a summary of our significant accounting policies. In general, these policies primarily relate to transactions recorded by EPD. The policies described below are those applicable to our consolidated balance sheet at December 31, 2004.

ALLOWANCE FOR DOUBTFUL ACCOUNTS is generally determined as a percentage of revenues for the last twelve months. Our procedure for recording an allowance for doubtful accounts is based on historical experience, financial stability of our customers and levels of credit granted to customers. In addition, we may also increase the allowance account in response to specific identification of customers involved in bankruptcy proceedings and those experiencing financial uncertainties. We routinely review our estimates in this area to ascertain that we have recorded sufficient reserves to cover forecasted losses. Our allowance for doubtful accounts was $24.3 million at December 31, 2004.

ASSET RETIREMENT OBLIGATIONS are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development, and/or normal operation. In determining asset retirement obligations, we must identify those legal obligations that we are required to settle as result of existing or enacted law, statute, ordinance, or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel.

SFAS No. 143, “Accounting for Asset Retirement Obligations,” addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and related asset retirement costs. It requires us to record the fair value of an asset retirement obligation (a liability) in the period in which it is incurred. When a liability is recorded, we will capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we will either settle the obligation for its recorded amount or incur a gain or loss upon settlement. We adopted SFAS No. 143 as of January 1, 2003. See Note 6 for information relating to our asset retirement obligations.

CASH AND CASH EQUIVALENTS are all highly liquid investments with an original maturity of less than three months at the date of purchase.

DEFERRED TAX assets and liabilities are recognized for temporary differences between the underlying assets and liabilities for financial reporting and tax purposes. Federal and state income taxes are applicable primarily to the Seminole Pipeline Company, which is a corporation and a subsidiary of the Operating Partnership. In general, EPD’s limited partnership structure is not subject to federal income taxes. As a result, its earnings and losses for federal income tax purposes are included in the tax returns of its partners.

On a standalone basis, EPGP (a limited liability company) was organized as a pass-through entity for federal income tax purposes. As a result, for federal income tax purposes, the Members are individually responsible for taxes of their allocable share of the taxable income of EPGP.

DOLLAR AMOUNTS presented in the tabulations within the notes to our consolidated balance sheet are stated in thousands of dollars, unless otherwise indicated.

ENVIRONMENTAL COSTS for remediation are accrued based on the estimates of known remediation requirements. Such accruals are based on management's estimate of the ultimate costs to remediate the site. Ongoing environmental compliance costs are charged to expense as incurred, and expenditures to mitigate or prevent future environmental contamination are capitalized. Environmental costs and related accruals were not significant prior to the GulfTerra Merger. As a result of the GulfTerra Merger, we have initially estimated an environmental liability of $21 million, which is included in other long-term liabilities on our consolidated balance sheet at December 31, 2004, for remediation costs expected to be incurred over time associated with mercury gas meters.

EXCESS COST OVER UNDERLYING EQUITY IN NET ASSETS (or "excess cost") denotes the excess of our cost (or purchase price) over our underlying equity in the net assets of our investees. At December 31, 2004, our investments in Promix, La Porte, Dixie, Neptune, Poseidon, Cameron Highway and Nemo included excess cost. The excess cost of these investments is reflected in our investments in and advances to unconsolidated affiliates for these entities.

We evaluate equity method investments (which include excess cost amounts attributable to tangible or intangible assets) for impairment whenever events or changes in circumstances indicate that there is a loss in value of the investment which is an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the investee or long-term negative changes in the investee’s industry. In the event that we determine that the loss in value of an investment is other than a temporary decline, we would record a charge to earnings to adjust the carrying value to fair value. See Note 7 for a further discussion of the excess cost related to these investments.

EXCHANGES are contractual agreements for the movements of NGL and petrochemical products between parties to satisfy timing and logistical needs of the parties. Net exchange volumes borrowed from us under such agreements are valued and included in accounts receivable, and net exchange volumes loaned to us under such agreements are valued and accrued as a liability in accrued gas payables.

FINANCIAL INSTRUMENTS such as swaps, forward and other contracts to manage the price risks associated with inventories, firm commitments, interest rates and certain anticipated transactions are used by the Company. We recognize our transactions on the balance sheet as assets and liabilities based on the instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. Changes in fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset related results of the hedge item in the income statement for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses on a cash flow hedge are reclassified into earnings when the forecasted transaction occurs. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.

To qualify as a hedge, the item to be hedged must expose us to commodity or interest rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness is recorded into earnings immediately. See Note 14 for a further discussion of our financial instruments.

GOODWILL represents the excess of amounts we paid for businesses and assets over the respective fair value of the underlying net assets purchased (see Note 8). Since adopting SFAS No. 142, “Goodwill and Other Intangible Assets”, on January 1, 2002, our goodwill amounts are no longer amortized but are assessed annually for recoverability. In addition, we periodically review the reporting units to which the goodwill amounts relate if impairment indicators are evident. If such indicators are present (i.e., loss of a significant customer, economic obsolescence of plant assets, etc.), the fair value of the reporting unit, including its related goodwill, will be calculated and compared to its combined book value. If the fair value of the reporting unit exceeds its book value, goodwill is not considered impaired and no adjustment to earnings would be required. Should the fair value of the reporting unit (including its goodwill) be less than its book value, a charge to earnings would be recorded to adjust goodwill to its implied fair value. We have not recognized any impairment losses related to our goodwill for any of the periods presented.

INTANGIBLE ASSETS consist primarily of the estimated value assigned to certain customer relationships and certain customer contracts (see Note 8). Our customer relationship intangible assets represent the customer base that GulfTerra and the South Texas midstream assets serve through providing services, including natural gas gathering and processing, NGL fractionation and pipeline transportation. These entities conduct the majority of their business through regular contact and the use of written contracts. The value of these customer relationships are being amortized using expected production curves associated with the underlying resource bases

(i.e., the oil and gas reserves associated with the intangible assets). Our estimate of the economic life of each resource base is based on a number of factors, including third-party reserve estimates, the economic viability of production and exploration activities and other industry factors.

Our contract-based intangible assets represent the rights we own arising from contractual agreements primarily within our natural gas and NGL operations. A contract-based intangible asset with a finite useful life is amortized over its estimated useful life based on the respective contract terms. Our estimate of useful life is also 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.

INVENTORIES primarily consist of NGL, petrochemical and natural gas volumes and are valued at the lower of average cost or market (see Note 5). Shipping and handling charges directly related to volumes we purchase or to which we take ownership are capitalized as costs of inventory. As these inventories are sold and delivered out of inventory, the average cost of these products (which includes freight-in charges which have been capitalized) are charged to current period operating costs and expenses. Shipping and handling charges for products we sell and deliver to customers are charged to operating costs and expenses as incurred.

LONG-LIVED ASSETS (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” Under SFAS No. 144, an asset shall be tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows.

NATURAL GAS IMBALANCES result when a customer delivers more or less gas into our pipelines than they take out. We generally value our imbalances using a twelve-month moving average of natural gas prices, which we believe is an appropriate assumption to estimate the value of the imbalances upon settlement given that the actual settlement dates may vary by customer. Changes in natural gas prices may impact our estimates. Prior to the GulfTerra Merger, natural gas imbalances were not significant.

At December 31, 2004, our imbalance receivables were $56.7 million and are reflected as a component of accounts receivable. At December 31, 2004, our imbalance payables were $59 million and are reflected as a component of accrued gas payables.

PROPERTY, PLANT AND EQUIPMENT is recorded at its original cost of construction or, upon acquisition, the fair value of the asset acquired. Our property, plant and equipment is generally depreciated using the straight-line method over the asset’s estimated useful life. Maintenance, repairs and minor renewals are charged to operations as incurred. The cost of assets retired or sold, together with the related accumulated depreciation, is removed from the accounts. Any gain or loss on disposition is included in operating income.

Additions and improvements to and major renewals of existing assets are capitalized and depreciated using the straight-line method over the estimated useful life of the new equipment or modifications. These expenditures result in a long-term benefit to the Company. See Note 6 for additional information regarding our property, plant and equipment.

RESTRICTED CASH includes amounts held by a brokerage firm as margin deposits associated with our financial instruments portfolio and for physical purchase transactions made on the NYMEX exchange. At December 31, 2004, cash and cash equivalents includes $26.2 million of restricted cash related to these requirements.

USE OF ESTIMATES AND ASSUMPTIONS by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet are required for the preparation of financial statements in conformity with accounting principles generally accepted in the United States of America. Our actual results could differ from these estimates.

3. RECENT ACCOUNTING DEVELOPMENTS

FIN 46, “Consolidation of Variable Interest Entities – An Interpretation of ARB No. 51.” This interpretation of ARB No. 51 addresses requirements for accounting consolidation of a variable interest entity (“VIE”) with its primary beneficiary. In general, if the equity owner of a VIE meets certain criteria defined within FIN 46, the assets, liabilities and results of the activities of the VIE should be included in the consolidated financial statements of the owner. Our adoption of FIN 46 (as amended by FIN 46R) in 2003 has had no material effect on our consolidated financial statements. Due to the complexity of FIN 46 (as amended by FIN 46R and interpreted), the FASB is continuing to provide guidance regarding implementation issues. Since this guidance is still continuing, our conclusions regarding the application of this guidance may be altered. As a result, adjustments may be recorded in future periods as we adopt new FASB interpretations of FIN 46.

SFAS No. 151, “Inventory Costs — an Amendment of ARB No. 43, Chapter 4.” This accounting guidance, which is applicable for fiscal years beginning after June 15, 2005, amends ARB No. 43, Chapter 4, to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) should be recognized as current period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. We do not expect the adoption of SFAS No. 151 to have a material impact on our financial position, results of operations or cash flows.

SFAS No. 123(R), “Share-Based Payment.” This accounting guidance, which is applicable for the first interim or annual reporting period beginning after June 15, 2005, replaces SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB No. 25, “Accounting for Stock Issued to Employees.” This Statement eliminates the ability to account for share-based compensation transactions using APB No. 25, and generally requires instead that such transactions be accounted for using a fair-value-based method.

This statement requires a public entity, such as EPD, to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award - the requisite service period (usually the vesting period). No compensation cost is recognized for equity instruments for which employees do not render the requisite service. Employee share purchase plans will not result in recognition of compensation cost if certain conditions are met; those conditions are much the same as the related conditions in SFAS No. 123.

A public entity will initially measure the cost of employee services received in exchange for an award of liability instruments based on its current fair value; the fair value of that award will be remeasured subsequently at each reporting date through the settlement date. Changes in fair value during the requisite service period will be recognized as compensation cost over that period.

The grant-date fair value of employee share options and similar instruments will be estimated using option-pricing models adjusted for the unique characteristics of those instruments (unless observable market prices for the same or similar instruments are available). If an equity award is modified after the grant date, incremental compensation cost will be recognized in an amount equal to the excess of the fair value of the modified award over the fair value of the original award immediately before the modification.

EPD is continuing to evaluate the provisions of SFAS No. 123(R) and will fully adopt the standard during 2005 within the prescribed time periods. Upon the required effective date, EPD will apply this statement using a modified version of prospective application as described in the standard.

4. BUSINESS COMBINATIONS

Acquisition of 50% membership interest in general partner of GulfTerra

Immediately prior to closing the GulfTerra Merger on September 30, 2004 (see below), we acquired El Paso’s 50% membership interest in GulfTerra Energy Company, L.L.C., the general partner of GulfTerra (“GulfTerra GP”), for $370 million in cash and the issuance of a 9.9% membership interest in the Company to El Paso. Subsequently, we contributed this 50% membership interest in GulfTerra GP to EPD without the receipt of additional general partner interest, common units or other consideration. We borrowed the $370 million used to acquire this interest from DDC, which obtained the funds through a loan from EPCO (which indirectly owns an 85.595% membership interest in us through DFI).

The fair value we assigned to the 50% membership interest in GulfTerra GP we acquired is based on 50% of an implied $922.7 million estimated total fair value of GulfTerra GP, which assumes that the $370 million cash payment made to El Paso represented consideration for a 40.1% interest in GulfTerra GP. The 40.1% interest was derived by deducting the 9.9% membership interest we granted to El Paso in this transaction from the 50% membership interest in GulfTerra GP that we received. The preliminary fair value of $461.3 million assigned to this voting membership interest compares favorably to the $425 million that EPD paid El Paso to purchase a 50% non-voting membership interest in GulfTerra GP in December 2003. We valued the 9.9% membership interest we granted to El Paso at $91.3 million, which equals the difference between the $461.3 preliminary fair value of the GulfTerra GP interest we acquired and the $370 million cash payment we made to El Paso.

Completion of the GulfTerra Merger by EPD

On September 30, 2004, EPD and GulfTerra completed the merger of GulfTerra with a wholly owned subsidiary of EPD. Additionally, EPD completed certain other transactions related to the merger, including receipt of Enterprise GP’s contribution of a 50% membership interest in GulfTerra GP (as discussed in the previous section of this Note 4) and the purchase of certain midstream energy assets located in South Texas from El Paso. The aggregate value of the total consideration EPD paid or issued to complete the GulfTerra Merger was approximately $4 billion.

As a result of the GulfTerra Merger, GulfTerra and GulfTerra GP became wholly owned subsidiaries of EPD on September 30, 2004. On October 1, 2004, we contributed our ownership interests in GulfTerra and GulfTerra GP to the Operating Partnership, which resulted in GulfTerra and GulfTerra GP becoming wholly owned subsidiaries of the Operating Partnership.

Formed in 1993, GulfTerra manages a balanced, diversified portfolio of interests and assets relating to the midstream energy sector, which involves gathering, transporting, separating, processing, fractionating and storing natural gas, oil and NGLs. GulfTerra's interests and assets included (i) offshore oil and natural gas pipelines, platforms, processing facilities and other energy infrastructure in the Gulf of Mexico, primarily offshore Louisiana and Texas; (ii) onshore natural gas pipelines and processing facilities in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas; (iii) onshore NGL pipelines and fractionation facilities in Texas; and (iv) onshore natural gas and NGL storage facilities in Louisiana, Mississippi and Texas.

The South Texas midstream assets consisted of nine natural gas processing plants with a combined capacity of 1.9 Bcf/d, a 294-mile natural gas gathering system, a natural gas treating facility with a capacity of 150 MMcf/d and a small NGL pipeline.

The GulfTerra Merger transactions

The GulfTerra Merger occurred in several interrelated transactions as described below.

•

Step One. On December 15, 2003, EPD purchased a 50% membership interest in GulfTerra GP from El Paso for $425 million in cash. GulfTerra GP owns a 1% general partner interest in GulfTerra. Prior to completion of the GulfTerra Merger, EPD accounted for its investment in GulfTerra GP using the equity method of accounting. The $425 million in funds required to complete Step One were borrowed under an

Interim Term Loan and pre-merger revolving credit facilities. This amount was fully repaid with the net proceeds from equity offerings EPD completed during 2004.

•	Step Two. On September 30, 2004, the GulfTerra Merger was consummated and GulfTerra and GulfTerra GP became wholly owned subsidiaries of EPD. Step Two of the GulfTerra Merger included the following transactions:

•

As discussed previously in this Note 4, we acquired El Paso’s remaining 50% membership interest in GulfTerra GP for $370 million in cash paid to El Paso and the issuance of a 9.9% membership interest in Enterprise GP to El Paso. Subsequently, we contributed this 50% membership interest in GulfTerra GP to EPD without the receipt of additional general partner interest, common units or other consideration.

•

Immediately prior to closing the GulfTerra Merger, EPD paid $500 million in cash to El Paso for 10,937,500 Series C units of GulfTerra and 2,876,620 common units of GulfTerra. The remaining 57,762,369 GulfTerra common units (7,433,425 of which were owned by El Paso) were converted into 104,549,823 EPD common units (13,454,499 of which are held by El Paso) at the time of the consummation of the GulfTerra Merger.

•	Step Three. Immediately after Step Two was completed, EPD acquired certain South Texas midstream assets from El Paso for $155.3 million in cash. Pursuant to written agreements, EPD's purchase of the South Texas midstream assets was effective September 1, 2004.

In connection with the closing of the GulfTerra Merger, on September 30, 2004, the Operating Partnership borrowed an aggregate $2.8 billion under its new revolving credit facilities in order to fund its cash payment obligations under Step Two and Step Three of the GulfTerra Merger and related transactions, including the tender offers for GulfTerra’s outstanding senior and senior subordinated notes. See Note 9 for a description of these new borrowing and debt-related transactions.

In January 2005, an affiliate of EPCO, acquired El Paso’s 9.9% membership interest in the Company and 13,454,499 of EPD's common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and affiliates own 100% of the membership interests of the Company and, at March 15, 2005, approximately 38.3% of EPD's total common units outstanding. El Paso no longer owns any interest in EPD or EPGP.

The total consideration EPD paid or granted for the GulfTerra Merger is summarized below:

Step One transaction:
Cash payment by EPD to El Paso for initial 50% membership interest
in GulfTerra GP (a non-voting interest) made in December 2003	$	425,000

Total Step One consideration		425,000

Step Two transactions:
Cash payment by EPD to El Paso for 10,937,500 GulfTerra Series C units
and 2,876,620 GulfTerra common units		500,000
Fair value of EPD equity interests granted to acquire remaining 50% membership interest in
GulfTerra GP (voting interest)		461,347
Fair value of EPD common units issued in exchange for remaining
GulfTerra common units		2,445,420
Fair value of other EPD equity interests granted for unit awards and Series F2 convertible units		4,004
Fair value of receivable from El Paso for transition support payments ⁽¹⁾		(40,313	)
Transaction fees and other direct costs incurred by EPD as a result of the GulfTerra Merger ⁽¹⁾		24,032

Total Step Two consideration		3,394,490

Total Step One and Step Two consideration		3,819,490

Step Three transaction:
Purchase of South Texas midstream assets from El Paso		155,277

Total consideration for Steps One through Three	$	3,974,767


(1) Reflects the present value of a contract-based receivable from El Paso received as part of the negotiated net consideration reached in Step One of the GulfTerra Merger. The agreements between Enterprise and El Paso provide that for a period of three years following the closing of the GulfTerra Merger, El Paso will make transition support payments to Enterprise in annual amounts of $18 million, $15 million and $12 million for the first, second and third years of such period, respectively, payable in twelve equal monthly installments for each such year. The $45 million receivable from El Paso has been discounted to fair value and recorded as a reduction in the purchase consideration for GulfTerra. As December 31, 2004, the fair value of the current portion and non-current portion of this contract-based receivable was $17.2 million and $23.1 million, respectively; these amounts are reflected as a component of “Prepaid and other current assets” and “Long-term receivables” on our Consolidated Balance Sheet as of December 31, 2004. (2) As a result of the GulfTerra Merger, Enterprise incurred expenses of approximately $24 million for various transaction fees and other direct costs. These direct costs include fees for legal, accounting, printing, financial advisory and other services rendered by third-parties to Enterprise over the course of the GulfTerra Merger transactions. This amount also includes $3.4 million of involuntary severance costs.

In connection with the GulfTerra Merger, we are required under a consent decree to sell our 50% interest in Starfish, which owns the Stingray natural gas pipeline and related gathering pipelines and dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana. In January 2005, we entered into a contract with a third party to sell this investment for approximately $41.2 million, and we closed the sale on March 31, 2005. The sale required FTC approval under the terms of the consent decree relating to the GulfTerra Merger. Additionally, under the same consent decree, we were required to sell our undivided 50% interest in a Mississippi propane storage facility by December 31, 2004. We sold our interest in this facility during the fourth quarter of 2004.

Other business combinations and asset acquisitions completed during 2004

During 2004, we also acquired an additional 16.7% interest in Tri-States; an additional 10% interest in Seminole; the remaining 33.3% ownership interest in BEF; and certain assets located in Morgan’s Point, Texas.

Acquisition of 16.7% interest in Tri-States. On April 1, 2004, we acquired an additional 16.7% membership interest in Tri-States, which owns an NGL pipeline located along the Mississippi, Alabama and Louisiana Gulf Coast. This system, in conjunction with the Wilprise and Belle Rose NGL pipelines, transport mixed NGLs to the BRF, Norco and Promix NGL fractionators located in south Louisiana. Due to this acquisition, our ownership interest in Tri-States increased to 66.7% and Tri-States became a majority-owned consolidated subsidiary of ours on April 1, 2004. Previously, Tri-States was accounted for as an equity method unconsolidated affiliate.

Acquisition of 10% interest in Seminole. On May 31, 2004, we acquired an additional 10% interest in Seminole, which owns a regulated 1,281-mile pipeline that transports mixed NGLs and NGL products from the Hobbs hub on the Texas-New Mexico border and the Permian Basin area to southeast Texas. As a result of this acquisition, our ownership interest in Seminole increased to 88.4%. The Seminole pipeline is interconnected with our Mid-America pipeline system at the Hobbs hub. The primary source of throughput for Seminole is volume originating from the Mid-America system.

Acquisition of remaining 33.3% interest in BEF. On September 1, 2004, we acquired the remaining 33.3% ownership interest in BEF, which owns a facility that produces octane additives such as MTBE (a motor gasoline additive that enhances octane and is used in reformulated gasoline). As a result of this acquisition, BEF became a wholly owned subsidiary of ours.

Acquisition of Morgan’s Point assets. On December 13, 2004, we acquired certain assets located in Morgan’s Point, Texas. The assets acquired primarily include an octane enhancement facility, a butane isomerization facility, a barge dock and NGL and petrochemical pipelines.

Allocation of purchase price of 2004 business combinations

The GulfTerra Merger transactions and our other business and asset acquisitions completed during 2004 were recorded using the purchase method of accounting. Purchase accounting requires us to allocate the cost of a business combination to the assets acquired and liabilities assumed based on their estimated fair values. We engaged an independent third-party business valuation expert to assess the fair values of the tangible and intangible assets of GulfTerra, the South Texas midstream assets, and those acquired in the Morgan's Point transaction. This information will assist management in the development of a definitive allocation of the overall purchase price of the GulfTerra Merger transactions. Management independently developed the fair value estimates for the other 2004 business acquisitions using recognized business valuation techniques.

The preliminary fair values shown in the following table are estimates based on information available to management at December 31, 2004. The valuation estimates shown below could change due to this recent transaction and the refinement of our estimates.

				Merger-Related Transactions
					Step Three
					Purchase of
				Step Two of	South Texas
				GulfTerra	Midstream	Other 2004
				Merger	Assets	Acquisitions	Total
Purchase price allocation:
	Assets acquired in business combination:
		Current assets, including cash of $40,453		$ 198,347	$ 7,614	$ 10,374	$ 216,335
		Property, plant and equipment, net		4,601,390	112,830	92,721	4,806,941
		Investments in and advances to
		unconsolidated affiliates		202,672		(42,597)	160,075
		Intangible assets		705,459	37,802	1,092	744,353
		Other assets		26,881			26,881
			Total assets acquired	5,734,749	158,246	61,590	5,954,585
	Liabilities assumed in business combination:
		Current liabilities		(228,566)	(2,969)	(2,329)	(233,864)
		Long-term debt, including current maturities		(2,015,583)			(2,015,583)
		Other long-term liabilities		(47,880)			(47,880)
		Minority interest				26,590	26,590
			Total liabilities assumed	(2,292,029)	(2,969)	24,261	(2,270,737)
			Total assets acquired less liabilities assumed	3,442,720	155,277	85,851	3,683,848
			Total consideration given	3,819,490	155,277	85,851	4,060,618
	Remaining Goodwill			$ 376,770	$ -	$ -	$ 376,770

As a result of the preliminary purchase price allocation for Steps Two and Three of the GulfTerra Merger, we recorded $744.4 million of amortizable intangible assets, primarily those related to customer relationships and contracts. The remaining preliminary amount represents goodwill of $376.8 million associated with our view of the future results from GulfTerra’s operations, based on the strategic location of GulfTerra’s assets as well as their industry relationships. For additional information regarding these intangible assets and goodwill, see Note 8. For the recent GulfTerra Merger and the related South Texas midstream assets, the allocation of the purchase price to the estimated fair values of assets and liabilities is based, in part, upon assistance from an independent third party business valuation expert. In addition, the Morgan's Point allocation (which is a component of "Other 2004 Acquisitions" as shown in the preceding table), is preliminary. Such preliminary values are subject to final valuation reports and additional information.

5. INVENTORIES

Our inventories consisted of the following at December 31, 2004:

Working inventory	$ 171,485
Forward-sales inventory	17,534
Inventory	$ 189,019

A general description of our inventories is as follows:

•

Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs and petrochemical products that are available for sale or used in the provision of services. This inventory is valued at the lower of average cost or market, with “market” being determined by industry-related posted prices such as those published by OPIS and CMAI.

•

The forward-sales inventory is comprised of segregated NGL volumes dedicated to the fulfillment of forward sales contracts and is valued at the lower of average cost or market, with “market” being defined as the weighted-average sales price for NGL volumes to be delivered in future months on the forward sales contracts.

In general, our inventory values reflect amounts we have paid for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection and demurrage charges and other handling and processing costs. In those instances where we take ownership of inventory volumes through percent-of-liquids and similar arrangements; the volumes are valued at market-related prices during the month in which they are acquired. Like the third-party purchases described above, we inventory the various ancillary costs such as freight-in and other handling and processing amounts associated with owned volumes obtained through our in-kind and similar contracts.

Due to fluctuating market conditions in the NGL, natural gas and petrochemical industry, we occasionally recognize lower of average cost or market (“LCM”) adjustments when the cost 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 and generally affect our segment operating results in the following manner:

•	NGL inventory write-downs are recorded as a cost of the Processing segment’s NGL marketing activities;
•	Natural gas inventory write downs are recorded as a cost of the Pipeline segment’s Acadian Gas operations; and
•	Petrochemical inventory write downs are recorded as a cost of the Fractionation segment’s petrochemical marketing activities or as a cost of the Octane Enhancement segment’s MTBE operations, as applicable.

6. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment and accumulated depreciation were as follows at December 31, 2004:

	Estimated Useful Life in Years
Plants and pipelines ⁽¹⁾	5-35 ⁽⁵⁾	$	7,691,197
Underground and other storage facilities ⁽²⁾	5-35 ⁽⁶⁾		531,394
Platforms and facilities ⁽³⁾	23-31		162,645
Transportation equipment ⁽⁴⁾	3-10		7,240
Land			29,142
Construction in progress			230,375

Total			8,651,993
Less accumulated depreciation			820,526

Property, plant and equipment, net		$	7,831,467


(1) Plants and pipelines includes processing plants; NGL, petrochemical, oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment; and related assets. (2) Underground and other storage facilities includes underground product storage caverns; storage tanks; water wells; and related assets. (3) Platforms and facilities includes offshore platforms and related facilities and other associated assets. (4) Transportation equipment includes vehicles and similar assets used in our operations. (5) In general, the estimated useful lives of major components of this category are: processing plants, 20-35 years; pipelines, 18-35 years (with some equipment at 5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings 20-35 years; and laboratory and shop equipment, 5-35 years. (6) In general, the estimated useful lives of major components of this category are: underground storage facilities, 20-35 years (with some components at 5 years); storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years).

Capitalized interest on our construction projects for the year ended December 31, 2004 was $2.8 million.

Asset retirement obligations. SFAS No. 143 establishes accounting standards for the recognition and measurement of an ARO liability and the associated asset retirement cost. As a result of the GulfTerra Merger, we assumed AROs associated with the future retirement obligations for certain limited offshore assets located in the Gulf of Mexico. The aggregate $6.2 million liability associated with this ARO is a component of “Other Long-Term Liabilities” at December 31, 2004.

In addition to the obligations we assumed in the GulfTerra Merger, we have also identified ARO liabilities in our other operational areas. These include ARO liabilities related to (i) right-of-way easements over property not owned by us and (ii) regulatory requirements triggered by the abandonment or retirement of certain currently operated facilities. As a result of our analysis of these identified AROs, we were not required to recognize such potential liabilities. Our rights under the easements are renewable and only require retirement action upon nonrenewal of the easement agreements. We currently expect to renew all such easement agreements and to use these properties for the foreseeable future. Should we decide not to renew these right-of-way agreements, an ARO liability would be recorded at that time. We also identified potential ARO liabilities arising from regulatory requirements related to the future abandonment or retirement of certain currently operated facilities. At present, we currently have no intention or legal obligation to abandon or retire such facilities. An ARO liability would be recorded if future abandonment or retirement of such facilities occurred.

Certain of our unconsolidated affiliates, Deepwater Gateway, Neptune, Nemo, and Starfish, had recorded ARO’s at December 31, 2004 relating to regulatory requirements. These amounts are immaterial.

7. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

We own interests in a number of related businesses that are accounted for using the equity method. In general, we use the equity method of accounting for an investment in which we own 20% to 50% of its outstanding ownership interests and exercise significant influence over its operating and financial policies. We do not exercise management control over our equity or cost method investees. As a result of recently issued accounting guidance under EITF 03-16, the minimum ownership requirement for an investment organized as a limited liability company (or "LLC") to qualify for the equity method of accounting was lowered to between 3% and 5% from the 20% threshold applied to other types of investments.

On July 1, 2004, we changed our method of accounting for VESCO from the cost method to the equity method in accordance with EITF 03-16. Our VESCO investment consists of a 13.1% interest in a LLC that owns a natural gas processing plant, NGL fractionation facilities, storage assets and gas gathering pipelines located in south Louisiana.

Our investments in and advances to these unconsolidated affiliates at December 31, 2004 are grouped in the following table according to the business segment to which they relate. For a general discussion of our business segments, see Note 15.

		Ownership
		Percentage
Offshore Pipeline & Services:
	Poseidon ⁽¹⁾	36.0%	$ 63,944
	Cameron Highway ⁽¹⁾	50.0%	114,354
	Deepwater Gateway⁽¹⁾	50.0%	56,527
	Offshore pipeline investments ⁽²⁾	Various	84,638
Onshore Natural Gas Pipeline & Services:
	Evangeline	49.5%	2,810
	Coyote ⁽¹⁾	50.0%	2,441
NGL Pipeline & Services:
	Dixie	19.9%	32,514
	VESCO	13.1%	38,437
	Belle Rose	41.7%	10,172
	Promix	50.0%	65,748
	BRF	32.3%	27,012
	Tri-States ⁽³⁾
Petrochemical Services:
	BRPC	30.0%	15,617
	La Porte	50.0%	4,950
Other:
	GulfTerra GP⁽⁴⁾
Total			$ 519,164

(1) Our ownership interest in these investments was acquired in connection with the GulfTerra Merger on September 30, 2004. (2) Reflects our collective investment in Neptune, Nemo and Starfish. In connection with the GulfTerra Merger, we were required under a consent decree published for comment by the FTC on September 30, 2004 to sell our 50% ownership interest in Starfish. The carrying value of our investment in Starfish was reclassified from “Investments in and Advances to Unconsolidated Affiliates” to “Assets Held for Sale” on our Consolidated Balance Sheet at December 31, 2004. On March 31, 2005, we sold our ownership interest in Starfish to a third party. (3) We acquired an additional 16.7% ownership interest in Tri-States in April 2004. As a result of this acquisition, Tri-States became a consolidated subsidiary. (4) In connection with the GulfTerra Merger (see Note 4), GulfTerra GP became a wholly owned consolidated subsidiary on September 30, 2004. We had previously accounted for our 50% ownership interest in GulfTerra GP as an equity method investment from December 15, 2003 through September 29, 2004.

On occasion, the price we pay to acquire an investment exceeds the underlying historical net assets (i.e., the underlying equity account balances on the books of the investee) that we purchase. These excess cost amounts are a component of our investments in and advances to unconsolidated affiliates. At December 31, 2004, our investments in Promix, La Porte, Dixie, Neptune, Poseidon, Cameron Highway and Nemo included excess cost. An analysis of each of these investments at the time of purchase indicated that such excess cost amounts were attributable to either (i) an increase in the fair value of the tangible assets owned by each entity over the investee's historical carrying values or (ii) it was unattributable to other specific assets (including intangible assets) and was deemed to be goodwill. To the extent that we attribute an excess cost amount to tangible or intangible assets, we amortize these amounts as a reduction in equity earnings in a manner similar to depreciation. To the extent we attribute an excess cost amount to goodwill, we do not amortize this amount but it is subject to evaluation for impairment. At December 31, 2004, excess cost amounts included in our investments in and advances to unconsolidated affiliates totaled $83.6 million, of which $74.3 million was attributed to tangible assets and the remainder to goodwill.

Offshore Pipelines & Services segment

At December 31, 2004, our Offshore Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

•

Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”) – a 36% interest in Poseidon, which owns a crude oil pipeline extending from the Gulf of Mexico to onshore Louisiana. Poseidon completed construction of its Front Runner oil pipeline in the third quarter of 2004 and received its first volumes from this new oil pipeline in January 2005. This new oil pipeline connects the Front Runner platform in the Gulf of Mexico with Poseidon’s existing system.

•

Cameron Highway Oil Pipeline Company (“Cameron Highway”) – a 50% interest in Cameron Highway, which owns a recently constructed crude oil pipeline system that connects various designated crude oil receipt points extending from Ship Shoal Block 332 in the Gulf of Mexico to onshore delivery points located in the state of Texas. We anticipate that operations will commence on this pipeline system in early 2005.

•

Deepwater Gateway, L.L.C. (“Deepwater Gateway”) – a 50% interest in Deepwater Gateway, which owns the Marco Polo tension-leg platform. The Marco Polo tension-leg platform is operated by Anadarko Petroleum Corporation (“Anadarko”) and processes oil and natural gas from Anadarko’s Marco Polo Field discovery located at Green Canyon Block 608 in the Gulf of Mexico. The Marco Polo tension-leg platform went into service during the third quarter of 2004.

•

Offshore pipeline investments - our collective investment in Neptune Pipeline Company, L.L.C. ("Neptune"), Nemo Gathering Company, LLC ("Nemo") and Starfish Pipeline Company, LLC ("Starfish"). We own a 25.7% interest in Neptune, which owns the Manta Ray and Nautilus natural gas pipeline systems located in the Gulf of Mexico offshore Louisiana. In addition, we own a 33.9% interest in Nemo, which owns the Nemo natural gas pipeline located in the Gulf of Mexico offshore Louisiana. This category also includes our 50% interest in Starfish, which owns the Stingray and Triton natural gas pipeline and related dehydration and other facilities located in south Louisiana and the Gulf of Mexico. In connection with the GulfTerra Merger, we were required under a consent decree published for comment by the FTC on September 30, 2004 to sell our 50% interest in Starfish by March 31, 2005. In January 2005, we entered into a contract with a third party to sell this investment for approximately $42.1 million, closed the sale on March 31, 2005. The sale required FTC approval under the terms of the consent decree relating to the GulfTerra Merger.

The combined balance sheet information of this segment's unconsolidated affiliates at December 31, 2004 is summarized below.

Current assets		$79,196
Property, plant and equipment, net		712,182
Other assets		528,443
	Total assets	$1,319,821

Current liabilities		$71,758
Other liabilities		526,990
Combined equity		721,073
	Total liabilities and combined equity	$1,319,821

Onshore Natural Gas Pipelines & Services segment

At December 31, 2004, our Onshore Natural Gas Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

•	Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively, "Evangeline") – an approximate 49.5% aggregate interest in a natural gas pipeline system located in south Louisiana.

•	Coyote Gas Treating, LLC (“Coyote”) – a 50% interest in Coyote, which owns a natural gas treating facility located in the San Juan Basin of southwestern Colorado.

The combined balance sheet information of this segment's unconsolidated affiliates at December 31, 2004 is summarized below.

Current assets		$21,652
Property, plant and equipment, net		38,821
Other assets		35,149
	Total assets	$95,622

Current liabilities		$24,365
Other liabilities		37,210
Combined equity		34,047
	Total liabilities and combined equity	$95,622

NGL Pipelines & Services segment

At December 31, 2004, our NGL Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

•	Dixie Pipeline Company ("Dixie") – an aggregate 19.9% interest in a 1,301-mile propane pipeline and associated facilities extending from Mont Belvieu, Texas to North Carolina.

•

Venice Energy Services Company, LLC ("VESCO") – a 13.1% interest in a natural gas processing plant, fractionation facilities, storage, and gas gathering pipelines located in southern Louisiana and, with respect to certain of the gas gathering pipelines, also in the Gulf of Mexico. On July 1, 2004, we changed our method of accounting for VESCO from the cost method to the equity method in accordance with EITF 03-16.

•	Belle Rose NGL Pipeline LLC ("Belle Rose") – a 41.7% interest in an NGL pipeline system located in south Louisiana.

•

K/D/S Promix LLC ("Promix") – a 50% interest in an NGL fractionator and related storage and pipeline assets located in south Louisiana. In December 2004, we acquired an additional 16.7% ownership interest in Promix from Koch. As a result of this purchase, our ownership interest in Promix increased to 50%.

•	Baton Rouge Fractionators LLC ("BRF") – an approximate 32.3% interest in an NGL fractionator located in southeastern Louisiana.

In March 2003, we purchased the remaining ownership interests in EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, “EPIK”), at which time EPIK became a consolidated subsidiary of ours. In October 2003, we purchased an additional 37.4% interest in Wilprise Pipeline Company, LLC (“Wilprise”), at which time it became a 74.7% owned consolidated subsidiary of ours. In April 2004, we purchased an additional 16.7% interest in Tri-States NGL Pipeline LLC (“Tri-States"), at which time it became a 66.7% owned consolidated subsidiary of ours. See Note 4 for additional information regarding our business combinations.

The combined balance sheet information of this segment's unconsolidated affiliates at December 31, 2004 is summarized below.

Current assets		$101,660
Property, plant and equipment, net		399,580
Other assets		16,993
	Total assets	$518,233

Current liabilities		$95,537
Other liabilities		13,422
Combined equity		409,274
	Total liabilities and combined equity	$518,233

Petrochemical Services segment

At December 31, 2004, our Petrochemical Services segment included the following unconsolidated affiliates accounted for using the equity method:

•	Baton Rouge Propylene Concentrator, LLC ("BRPC") – a 30% interest in a propylene fractionator located in southeastern Louisiana.

•	La Porte Pipeline Company, L.P. and La Porte Pipeline GP, LLC (collectively “La Porte”) – an aggregate 50% interest in a polymer grade propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas.

In November 2003, we purchased the remaining 50% of outstanding common stock of Olefins Terminal Corporation (“OTC”). As a result, OTC became a wholly owned subsidiary of ours. See Note 4 for additional information regarding our business combinations.

In September 2003, we acquired an additional 33.3% interest in Belvieu Environmental Fuels (“BEF”), which owns a facility that historically produced MTBE, a motor gasoline additive that enhanced octane values and is used in reformulated motor gasoline. As a result of this acquisition, BEF became a majority-owned consolidated subsidiary of ours on September 30, 2003. Previously, BEF was accounted for as an equity-method unconsolidated affiliate. In September 2004, we acquired the remaining 33.3% interest in BEF.

As a result of declining domestic demand and a prolonged period of weak MTBE production economics, several of BEF’s competitors announced their withdrawal from the marketplace during 2003. Due to the deteriorating business environment and outlook and the completion of its preliminary engineering studies regarding conversion alternatives, BEF evaluated the carrying value of its long-lived assets for impairment during the third quarter of 2003. This review indicated that the carrying value of its long-lived assets exceeded their collective fair value, which resulted in a non-cash asset impairment charge of $67.5 million. Our share of this loss was $22.5 million.

BEF’s assets were written down to fair value, which was determined by independent appraisers using present value techniques. The impaired assets principally represent the plant facility and other assets associated with MTBE production. The fair value analysis incorporates probability-weighted cash flows for future courses of action being taken (or contemplated to be taken) by BEF management, including modification of the facility to produce iso-octane and alkylate. If the underlying assumptions in the fair value analysis change resulting in the present value of expected future cash flows being less than the new carrying value of the facility, additional impairment charges may result in the future. See Note 13 for additional information regarding risks associated with our investment in BEF.

The combined balance sheet information of this segment's unconsolidated affiliates at December 31, 2004 is summarized below.

Current assets		$3,266
Property, plant and equipment, net		57,516
	Total assets	$60,782

Current liabilities		$438
Combined equity		60,344
	Total liabilities and combined equity	$60,782

Other, non-segment

The Other, non-segment category is presented for financial reporting purposes only to show the historical equity earnings we received from our 50% membership interest in the general partner of GulfTerra, GulfTerra Energy Company, L.L.C. (“GulfTerra GP”), which owns a 1.0% general partner interest in GulfTerra. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger (see Note 4). Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours.

8. INTANGIBLE ASSETS AND GOODWILL

Intangible assets. The following table summarizes our intangible assets at December 31, 2004:

		Gross	Accum.	Carrying
		Value	Amort.	Value
Offshore Pipelines & Services:
	Offshore pipeline & platform customer relationships ⁽¹⁾	$ 205,845	$ (6,965)	$ 198,880
	Independence Hub	1,167		1,167
	Segment total	207,012	(6,965)	200,047
Onshore Natural Gas Pipelines & Services:
	San Juan Gathering System customer relationships ⁽¹⁾	331,311	(6,222)	325,089
	Permian Basin customer relationships ⁽¹⁾	1,590	(57)	1,533
	Petal natural gas storage contracts ⁽¹⁾	86,726	(1,558)	85,168
	Hattiesburg natural gas storage contracts ⁽¹⁾	13,773	(501)	13,272
	San Juan Basin water rights ⁽¹⁾	750	(6)	744
	Segment total	434,150	(8,344)	425,806
NGL Pipelines & Services:
	Shell natural gas processing agreement	206,216	(45,110)	161,106
	Toca-Western natural gas processing contracts	11,187	(1,444)	9,743
	Toca-Western NGL fractionation contracts	20,042	(2,589)	17,453
	Mont Belvieu Storage II contracts	8,127	(697)	7,430
	Venice contracts	6,635	(601)	6,034
	STMA customer relationships ⁽¹⁾	37,802	(1,308)	36,494
	NGL Business customer relationships ⁽¹⁾	32,800	(829)	31,971
	Markham NGL storage contracts ⁽¹⁾	32,664	(1,088)	31,576
	Morgan’s Point⁽²⁾	1,652		1,652
	Segment total	357,125	(53,666)	303,459
Petrochemical Services:
	Mont Belvieu Splitter III contracts	53,000	(4,417)	48,583
	BEF UOP License Fee	1,097	(109)	988
	Port Neches pipeline contracts	2,400	(682)	1,718
	Segment total	56,497	(5,208)	51,289
	Total all segments	$ 1,054,784	$ (74,183)	$ 980,601

(1) These intangible assets were acquired as a result of the GulfTerra Merger and the South Texas midstream assets in September 2004. These amounts are based on our preliminary purchase price allocation for the GulfTerra Merger (see Note 4), which is subject to change. (2) These intangible assets were acquired in December 2004 in connection with our acquisition of the Morgan's Point assets. The amounts assigned to intangible assets are based upon our preliminary allocation of the acquisition purchase price, which is subject to change.

As of December 31, 2004, our primary intangible assets were as follows:

•

GulfTerra and STMA customer relationships. These intangible assets represent the customer base that GulfTerra and the South Texas midstream assets serve through providing services, including natural gas gathering and processing, NGL fractionation and pipeline transportation. These entities conduct the majority of their business through the use of written contracts; thus, the customer relationships represent the rights we own arising from those contractual agreements. We amortize the customer relationship values using a method that closely resembles the pattern in which the economic benefits of the underlying oil and natural gas resource bases from which the customers produce are consumed or otherwise used. This group of intangible assets consists of our (i) Offshore Pipelines & Platforms customer relationships; (ii) San Juan Gathering System customer relationships; (iii) Permian Basin customer relationships; (iv) STMA customer relationships and (v) NGL Business customer relationships.

•

GulfTerra storage contracts. These intangible assets represent the contracts that GulfTerra entered into to provide for the storage of natural gas or NGLs for various customers at its Petal and Hattiesburg natural gas or Markham NGL storage facilities. These contracts are amortized on a straight-line basis over the remainder of their respective contract terms, which we estimate range from 2 to 18 years. This group of intangible assets consists of our (i) Petal natural gas storage contracts; (ii) Hattiesburg natural gas storage contracts and (iii) Markham NGL storage contracts.

•

Shell natural gas processing agreement. We acquired this intangible asset in connection with our acquisition of certain midstream energy assets from Shell located along the Gulf Coast in 1999. The value of the Shell agreement is being amortized on a straight-line basis over the remainder of its initial 20-year contract term through 2019. For additional information regarding our related party relationship with Shell, see Note 12.

•

Mont Belvieu storage and propylene fractionation contracts. We acquired these storage and propylene fractionation contracts during 2002 in connection with our purchase of certain midstream energy assets from Diamond-Koch that were located in Mont Belvieu, Texas. The values of these contracts are being amortized on a straight-line basis over the 35-year remaining economic life of the assets to which they relate. This group of intangible assets consists of our Mont Belvieu Storage II contracts and Mont Belvieu Splitter III contracts.

•

Toca-Western contracts. We acquired these natural gas processing and NGL fractionation contracts during 2002 in connection with our purchase of certain midstream energy assets from Toca-Western. The Toca-Western natural gas processing contracts are being amortized on a straight-line basis over the expected 20-year economic life of the natural gas supplies supporting these contracts. The value of the Toca-Western NGL fractionation contracts is being amortized on a straight-line basis over the expected 20-year remaining life of the assets to which they relate.

Our remaining intangible assets primarily represent the value of contracts rights we own under product handling and transportation agreements, processing license agreements and water rights. In general, the value of these contract rights are being amortized using the straight-line method over either the terms of underlying contracts or the remaining useful economic life of the assets to which they relate.

Goodwill. In general, goodwill represents the excess of the purchase price of an acquired entity over the amounts assigned to assets acquired (including identifiable intangible assets) and liabilities assumed. Goodwill is not amortized; however, it is subject to annual impairment testing. Our preliminary estimate of goodwill associated with the GulfTerra Merger is $376.8 million, which we allocated between our new business segments in proportion to the tangible and intangible assets we recorded for this transaction in purchase accounting. The “GulfTerra Merger” goodwill is associated with our view of the future results from GulfTerra’s operations, based on the strategic location of GulfTerra’s assets as well as their industry relationships. Based on miles of pipelines, GulfTerra is one of the largest natural gas gathering and transportation companies providing services to producers in the natural gas supply regions of the central and western Gulf of Mexico and onshore in Texas and New Mexico. These regions, especially the deepwater regions of the Gulf of Mexico, offer us significant growth potential through the acquisition and construction of additional pipelines, platforms, processing and storage facilities and other midstream energy infrastructure. Since we have not finalized our allocation of the purchase price associated with the GulfTerra Merger, our estimate of goodwill related to this transaction is preliminary (see Note 4). The remainder of our goodwill amounts are associated with prior acquisitions, principally that of our purchase of propylene fractionation assets from Diamond-Koch in February 2002.

The following table summarizes our goodwill amounts at December 31, 2004:

Offshore Pipelines & Services
	GulfTerra Merger		$ 62,348
Onshore Natural Gas Pipelines & Services
	GulfTerra Merger		290,397
NGL Pipelines & Services
	GulfTerra Merger		24,026
	Acquisition of interest in Mont Belvieu NGL fractionator		7,857
	Acquisition of interest in Wilprise		880
Petrochemical Services
	Acquisition of Mont Belvieu propylene fractionation assets		73,690
		Totals	$ 459,198

9. DEBT OBLIGATIONS

Our debt consisted of the following at December 31, 2004:

Operating Partnership debt obligations:
	Interim Term Loan, variable rate, repaid in May 2004 ⁽¹⁾
	364-Day Revolving Credit Facility, variable rate, terminated in September 2004 ⁽²⁾
	Multi-Year Revolving Credit Facility, variable rate, terminated in September 2004 ⁽²⁾
	364-Day Acquisition Credit Facility, variable rate, repaid in February 2005 ^{(3, 4)}		$ 242,229
	Multi-Year Revolving Credit Facility, variable rate, due September 2009 ^(2,4)		321,000
	Seminole Notes, 6.67% fixed-rate, $15 million due in December 2005 ⁽⁵⁾		15,000
	MBFC Loan, 8.70% fixed-rate, due March 2010		54,000
	Senior Notes A, 8.25% fixed-rate, repaid March 2005		350,000
	Senior Notes B, 7.50% fixed-rate, due February 2011		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
	Senior Notes E, 4.00% fixed-rate, due October 2007		500,000
	Senior Notes F, 4.625% fixed-rate, due October 2009		500,000
	Senior Notes G, 5.60% fixed-rate, due October 2014		650,000
	Senior Notes H, 6.65% fixed-rate, due October 2034		350,000
GulfTerra debt obligations: ⁽⁵⁾
	Senior Notes, 6.25% fixed-rate, due June 2010⁽⁶⁾		750
	Senior Subordinated Notes, 8.50% fixed-rate, due June 2010		3,858
	Senior Subordinated Notes, 8.50% fixed-rate, due June 2011		1,777
	Senior Subordinated Notes, 10.625% fixed-rate, due December 2012		84
EPGP related party obligation:
	$370 Million Note, 6.25% fixed-rate, final installment due November 2019		366,433
		Total principal amount	4,655,131
Net unamortized discounts			(9,239)
Other			1,777
		Subtotal long-term debt	4,647,669
Less current maturities of debt ⁽⁷⁾			(18,450)
		Long-term debt	$ 4,629,219

Standby letters of credit outstanding ⁽⁸⁾			$ 139,052

(1) We used the proceeds from EPD's May 2004 common unit offering to fully repay and terminate the Interim Term Loan. (2) These facilities were terminated on September 30, 2004, and replaced by a new Multi-Year Revolving Credit Facility having $750 million of borrowing capacity due September 2009. (3) We used the proceeds from EPD's February 2005 common unit offering to fully repay and terminate the 364-Day Acquisition Credit Facility. (4) These facilities became effective concurrently with the closing of the GulfTerra Merger on September 30, 2004. The new $750 million Multi-Year Revolving Credit Facility replaced the $230 million 364-Day Revolving Credit Facility and the $270 million then existing Multi-Year Revolving Credit Facility. The $750 million borrowing capacity is reduced by the amount of standby letters of credit outstanding. (5) Solely as it relates to the assets of our GulfTerra and Seminole subsidiaries, our senior indebtedness is structurally subordinated and rank junior in right of payment to indebtedness of GulfTerra and Seminole. (6) Remaining notes outstanding were called and retired in February 2005. (7) In accordance with SFAS No. 6, "Classification of Short-Term Obligations Expected to Be Refinanced," long-term and current maturities of debt at December 31, 2004 reflected (i) our refinancing of Senior Notes A with proceeds from our Senior Notes I and J in March 2005 and (ii) the repayment of our 364-Day Acquisition Credit Facility using proceeds from EPD's equity offering completed in February 2005. Our classification of current maturities of debt at December 31, 2003 reflected our option and ability to convert any revolving credit balance outstanding at maturity under the 364-Day Revolving Credit Facility to a one-year term loan (which would have been due October 2005) in accordance with the terms of the agreement. (8) Of the $139 million standby letters of credit outstanding at December 31, 2004, $24 million were issued under our Multi-Year Revolving Credit Facility, and the remaining $115 million is associated with a letter of credit facility we entered into in November 2004 in connection with our Independence Hub capital project.

General description of consolidated debt

The following is a summary of the significant aspects of our debt obligations at December 31, 2004:

Parent-Subsidiary guarantor relationships. Through guarantor agreements which are nonrecourse to us, EPD acts as guarantor of the debt obligations of its Operating Partnership, with the exception of the Seminole Notes and the senior and senior subordinated notes of GulfTerra. If the Operating Partnership were to default on any debt EPD guarantees, EPD would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 86.6% of its capital stock). The senior and senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).

GulfTerra’s Senior Subordinated and Senior Notes. As a result of completing the GulfTerra Merger on September 30, 2004, EPD recorded in consolidation GulfTerra’s $921.5 million of outstanding senior and senior subordinated notes. Of this amount, $915 million was purchased on October 5, 2004 by the Operating Partnership pursuant to its tender offers. The note holders also approved amendments in connection with accepting the tender offers that removed all restrictive covenants governing the notes. For additional information regarding the tender offers, please read “ – 364-Day Acquisition Credit Facility – Tender offers for GulfTerra senior and senior subordinated notes” within this general description of debt. In February 2005, EPD redeemed, at a premium, the remaining $0.8 million outstanding under GulfTerra’s 6.25% senior notes due June 2010.

$370 Million Note Payable. On September 30, 2004, we borrowed $370 million from DDC, which owns a 4.5% membership interest in the Company. We used the proceeds from this borrowing to fund the cash portion of the consideration paid to El Paso for a 50% membership interest in GulfTerra GP (see Note 4). This promissory note bears a fixed-interest rate of 6.25%. Installment payments of $6.6 million are due quarterly from November 2004 through November 2019. Under terms of the note agreement, we are allowed to defer up to $13.2 million of scheduled quarterly installment payments at any time, except that all principal and accrued interest must be repaid by the November 2019 maturity date.

364-Day Acquisition Credit Facility. In August 2004, the Operating Partnership entered into a new 364-day credit agreement. The $2.25 billion Acquisition Credit Facility was an unsecured 364-day facility that was used to provide interim financing for certain transactions associated with the GulfTerra Merger, the refinancing of GulfTerra’s existing secured credit facility and term loans and the purchase of GulfTerra’s senior and senior subordinated notes in connection with the Operating Partnership’s tender offers for those notes. This facility became effective concurrent with the closing of the GulfTerra Merger and was to mature on September 29, 2005. In February 2005, we fully repaid and terminated the 364-Day Acquisition Credit Facility using proceeds received from EPD's February 2005 common unit offering. See Note 17 for additional information regarding EPD's February 2005 common unit offering.

As defined by the credit agreement, variable interest rates charged under this facility generally bore interest, at our election at the time of each borrowing, at (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus ½% or (2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate.

This credit agreement provided for the mandatory prepayment of loans and termination of commitments equal to the proceeds from and upon the consummation of any public or private debt or equity offerings by EPD on or after August 15, 2004, excluding equity issued with respect to EPD's distribution reinvestment plan, employee unit purchase plan and the exercise of any outstanding options with respect to EPD's common units. With the completion of the Operating Partnership's private offering of senior notes on October 4, 2004, we repaid approximately $2 billion borrowed under this facility, which reduced our borrowing capacity under this facility by an equal amount.

This revolving credit agreement contained various covenants related to our ability to incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; and make certain investments. The loan agreement also required the Operating Partnership to satisfy certain financial covenants at the end of each fiscal quarter. The Operating Partnership is in compliance with these covenants at December 31, 2004.

Tender offers for GulfTerra senior and senior subordinated notes

On August 4, 2004, in anticipation of completing the GulfTerra Merger, the Operating Partnership commenced four cash tender offers to purchase any and all of the outstanding senior and senior subordinated notes of GulfTerra having a total outstanding principal amount of approximately $921.5 million. In connection with the tender offers, GulfTerra executed supplements to the indentures governing these notes that eliminated certain restrictive covenants and default provisions contained in those indentures upon our purchase of more than a majority in principal amount of each series of the outstanding senior and senior subordinated notes.

Substantially all of the GulfTerra notes ($915 million of $921.5 million) were tendered pursuant to the tender offers. On September 30, 2004, the Operating Partnership borrowed $1.1 billion under its 364-Day Acquisition Credit Facility in anticipation of completing the tender offers and placed these funds in escrow. On October 5, 2004, the Operating Partnership purchased the notes for a total price of approximately $1.1 billion, which included $27 million related to consent payments.

The following table shows the four GulfTerra senior debt obligations affected, including the principal amount of each series of notes tendered, as well as the payment made by the Operating Partnership to complete the tender offers.

		Cash payments made by the
	Principal	Operating Partnership
	Amount	Accrued	Tender	Total
Description	Tendered	Interest	Price ⁽¹⁾	Paid
8.50% Senior Subordinated Notes due 2010
(Represents 98.2% of principal amount outstanding)	$ 212,057	$ 6,209	$ 246,366	$ 252,575
10.625% Senior Subordinated Notes due 2012
(Represents 99.9% of principal amount outstanding)	133,916	4,901	167,612	172,513
8.50% Senior Subordinated Notes due 2011
(Represents 99.5% of principal amount outstanding)	319,823	9,364	359,379	368,743
6.25% Senior Notes due 2010
(Represents 99.7% of principal amount outstanding)	249,250	5,366	274,073	279,439
Totals	$ 915,046	$ 25,840	$ 1,047,430	$ 1,073,270

(1) Tender price includes consent payment of $30 per $1,000 principal amount tendered.

Multi-Year Revolving Credit Facility. In August 2004, the Operating Partnership entered into a five-year $750 million revolving credit agreement that includes a sublimit of $100 million for standby letters of credit. This facility became effective concurrent with the closing of the GulfTerra Merger and will mature on September 30, 2009. This facility replaced the Operating Partnership's then existing $270 million Multi-Year Revolving Credit Facility and $230 million 364-Day Revolving Credit Facility, which were terminated upon the effective date of the new facility. The Operating Partnership’s borrowings under this agreement are unsecured general obligations that are non-recourse to us. EPD has guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.

As defined by the credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus ½% or (2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate. This revolving credit agreement contains various covenants similar to those of the Operating Partnership's 364-Day Acquisition Credit Facility. The Operating Partnership is in compliance with these covenants at December 31, 2004.

Senior Notes A, B, C and D. These fixed-rate notes are an unsecured obligation of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. They are senior to any future subordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to us. EPD has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes are subject to make-whole redemption rights and were issued under an indenture containing certain covenants. These covenants restrict the Operating Partnership's ability, with certain

exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. The Operating Partnership was in compliance with these covenants at December 31, 2004. On March 15, 2005, the Operating Partnership repaid the $350 million in indebtedness outstanding under Senior Notes A using the proceeds received from EPD's February 2005 private offering of senior notes. See Note 17 for information regarding this subsequent event.

Senior Notes E, F, G and H. On September 23, 2004, the Operating Partnership priced a private offering of an aggregate of $2 billion in principal amount of senior unsecured notes in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended. On October 4, 2004, these notes were issued. The interest rate, principal amount and net proceeds, before expenses, for each senior note in this offering are shown in the following table:

	Fixed			Proceeds to
	Interest	Principal	Bond	Us, Before
Senior Note Issued	Rate	Amount	Discount	Expenses
Senior Notes E, due October 2007	4.000%	$ 500,000	$ 2,140	$ 497,860
Senior Notes F, due October 2009	4.625%	500,000	4,405	495,595
Senior Notes G, due October 2014	5.600%	650,000	4,784	645,216
Senior Notes H, due October 2034	6.650%	350,000	4,203	345,797
Totals		$ 2,000,000	$ 15,532	$ 1,984,468

The net proceeds from this offering were used to reduce debt amounts outstanding under the Operating Partnership’s $2.25 billion 364-Day Acquisition Credit Facility that was used to partially fund the GulfTerra Merger on September 30, 2004.

These fixed-rate notes are unsecured obligations of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to us. EPD has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes were issued under an indenture containing certain covenants, which restrict the Operating Partnership's ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. The Operating Partnership is in compliance with these covenants at December 31, 2004.

On January 24, 2005, the Operating Partnership filed a registration statement for an offer to exchange these notes for registered debt securities with identical terms.

Senior Notes Offering. On February 15, 2005, the Operating Partnership sold $500 million in principal amount of senior notes in a private offering. See Note 17 for information regarding this subsequent event.

Pascagoula MBFC Loan. In connection with the construction of our Pascagoula, Mississippi natural gas processing plant, the Operating Partnership entered into a ten-year fixed-rate loan with the Mississippi Business Finance Corporation ("MBFC"). This loan is subject to a make-whole redemption right and is guaranteed by EPD through an unsecured and unsubordinated guarantee. The Pascagoula MBFC Loan contains certain covenants including the maintenance of appropriate levels of insurance on the Pascagoula facility. We were in compliance with the covenants at December 31, 2004.

The indenture agreement for this loan contains an acceleration clause whereby if our credit rating by Moody's declines below Baa3 in combination with our credit rating at Standard & Poor's remaining at BB+ or below, the $54 million principal balance of this loan, together with all accrued and unpaid interest would become immediately due and payable 120 days following such event. If such an event occurred, we would have to either redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to support our obligation under this loan.

Petal Industrial Development Revenue Bonds. In April 2004, Petal Gas Storage L.L.C. (“Petal”), a wholly owned subsidiary of GulfTerra, borrowed $52 million from the MBFC pursuant to a loan agreement between Petal and the MBFC. On the same date, the MBFC issued $52 million in Industrial Development Revenue Bonds to another wholly owned subsidiary of GulfTerra. The loan agreement and the Industrial Development Revenue Bonds

have identical fixed interest rates of 6.25% and maturities of fifteen years. The bonds and the associated tax exemptions are authorized under the Mississippi Business Finance Act. Petal may repay the loan agreement without penalty, and thus cause the Industrial Development Revenue Bonds to be redeemed, any time after one year from their date of issue. We have netted the loan amount and the bond amount of $52 million and the interest payable and interest receivable amount of $2.2 million on our consolidated balance sheet at December 31, 2004. Our presentation of the Petal Industrial Development Revenue Bonds is reflected in accordance with the provisions of FIN No. 39, “Offsetting of Amounts Related to Certain Contracts”, and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities”, since we have the ability and intent to offset these items.

Loss due to write-off of unamortized debt issuance costs. As a result of terminating our 364-Day Revolving Credit Facility and our previous Multi-Year Revolving Credit Facility on September 30, 2004, we expensed $0.7 million of unamortized debt issuance costs.

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 during 2004.

		Weighted-
	Range of	average
	interest rates	interest rate
	paid	paid
Interim Term Loan (terminated May 2004)	1.72% to 1.78%	1.76%
364-Day Revolving Credit Facility (terminated September 30, 2004)	1.72% to 4.00%	1.82%
Multi-Year Revolving Credit Facility (terminated September 30, 2004)	1.67% to 4.25%	1.83%
364-Day Acquisition Credit Facility (effective September 30, 2004)	2.67% to 4.75%	3.50%
Multi-Year Revolving Credit Facility (effective September 30, 2004)	2.64% to 5.25%	3.06%

Consolidated debt maturity table

The following table shows scheduled maturities of the principal amounts of our debt obligations for the next 5 years and in total thereafter.

2005	$ 18,450
2006	3,802
2007	504,045
2008	4,242
2009	825,576
Thereafter	3,299,016
Total scheduled principal to be repaid	$ 4,655,131

In accordance with SFAS No. 6, "Classification of Short-Term Obligations Expected to Be Refinanced", the amount shown in the table above for 2005 excludes the $242.2 million principal amount due under our 364-Day Acquisition Credit Facility at December 31, 2004. We refinanced this short-term obligation using proceeds from EPD's equity offering completed in February 2005. As a result, we have reclassified this amount to long-term debt and shown it as a component of principal amounts due after 2009.

In addition, the long-term portion of our debt obligations at December 31, 2004 reflects our refinancing of the $350 million in principal amount Senior Notes A (due March 2005) with proceeds from the Operating Partnership's March 2005 issuance of $250 million in principal amount Senior Notes I (due March 2015) and the Operating Partnership's $250 million in principal amount Senior Notes J (due March 2035). In accordance with SFAS No. 6, the principal amount due under Senior Notes A has been reclassified to amounts due after 2009 to match the scheduled maturities of Senior Notes I and J.

Joint venture debt obligations

We have ownership interests in four joint ventures having long-term debt obligations. The following table shows (i) our ownership interest in each entity at December 31, 2004, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate at December 31, 2004, on a 100% basis to the joint venture and (iii) the corresponding scheduled maturities of such long-term debt.

	Our		Scheduled Maturities of Long-Term Debt
	Ownership							After
	Interest	Total	2005	2006	2007	2008	2009	2009
Cameron Highway⁽¹⁾	50.0%	$ 297,000		$ 8,125	$ 32,500	$ 164,375	$ 16,000	$ 76,000
Deepwater Gateway	50.0%	144,000	$ 22,000	22,000	22,000	22,000	56,000
Poseidon	36.0%	107,000				107,000
Evangeline	49.5%	35,650	5,000	5,000	5,000	5,000	5,000	10,650
Total		$ 583,650	$ 27,000	$35,125	$ 59,500	$ 298,375	$ 77,000	$ 86,650

(1) The scheduled maturities for Cameron Highway assume that the construction loan is or will be converted into a term loan in July 2005 and scheduled repayments will begin on December 31, 2006.

The following is a summary of the significant aspects of the debt obligations of our unconsolidated affiliates.

Cameron Highway. In July 2003, Cameron Highway entered into a $325 million project loan facility, consisting of a $225 million construction loan and $100 million of senior secured notes, to finance a substantial portion of the cost to construct the Cameron Highway oil pipeline.

The construction loan bears interest at a variable rate. Once the Cameron Highway oil pipeline has commenced operations and transported a certain level of volumes (as specified in the credit agreement), the construction loan will convert to a term loan maturing in July 2008, subject to the terms of the loan agreement. At the end of the first quarter following the first anniversary of the conversion into a term loan, Cameron Highway will be required to make quarterly principal payments of $8.1 million, with the remaining unpaid principal amount payable on the maturity date. If the construction loan fails to convert into a term loan by January 2006, the construction loan and senior secured notes become fully due and payable. At December 31, 2004, Cameron Highway had $197 million outstanding under its construction loan at an average interest rate of 5.48%.

The interest rate on Cameron Highway's senior secured notes is 3.25% over the rate on 10-year U.S. Treasury securities. Principal payments of $4 million are due quarterly from September 2008 through December 2011, $6 million each from March 2012 through December 2012, and $5 million each from March 2013 through the principal maturity date of December 2013. At December 31, 2004, Cameron Highway had $100 million outstanding under its senior secured notes at an average interest rate of 7.36%.

The project loan facility as a whole is secured by (1) substantially all of Cameron Highway's assets, including, upon conversion to a term loan, a debt service reserve capital account, and (2) all of the equity interest in Cameron Highway. Other than the pledge of our equity interest and our construction obligations under the relevant producer agreements, the debt is non-recourse to us. The construction loan and senior secured notes prohibit Cameron Highway from making distributions to us until the construction loan is converted into a term loan and Cameron Highway meets certain financial requirements.

Deepwater Gateway. In August 2002, Deepwater Gateway, our unconsolidated affiliate which owns the Marco Polo tension-leg platform, obtained a $155 million project finance loan to finance a substantial portion of the cost to construct the Marco Polo tension-leg platform and related facilities. Construction of the Marco Polo tension-leg platform was completed during the first quarter of 2004, and in June 2004, Deepwater Gateway converted the project finance loan into a term loan which matures in June 2009. The term loan is payable in twenty equal quarterly installments of $5.5 million each (which began on September 30, 2004), and the remaining outstanding principal of $45 million is due on the maturity date. Interest rates are variable and the loan is collateralized by

substantially all of Deepwater Gateway’s assets. Deepwater Gateway is required to maintain a debt service reserve of not less than the projected principal, interest and fees due on the term loan for the immediately succeeding six month period. If Deepwater Gateway defaults on its payment obligations under the term loan, we would be required to pay the lenders all distributions we or any of our subsidiaries had received from Deepwater Gateway up to $22.5 million. As of December 31, 2004, the average interest rate charged under this term loan was 4.42%.

Poseidon. Poseidon is party to a $170 million revolving credit facility which matures in January 2008. The interest rates Poseidon is charged on balances outstanding under its revolving credit facility are variable and depend on its ratio of total debt to earnings before interest, taxes, depreciation and amortization. This credit agreement is secured by substantially all of Poseidon’s assets. As of December 31, 2004, the average interest rate charged under Poseidon’s revolving credit facility was 4.58%.

Evangeline. At December 31, 2004, long-term debt for Evangeline consisted of (i) $28.2 million in principal amount of 9.9% fixed-rate Series B senior secured notes that are due in December 2010 and (ii) a $7.5 million subordinated note payable. The Series B senior secured notes are collateralized by Evangeline’s property, plant and equipment; proceeds from a gas sales contract; and by a debt service requirement. Scheduled principal repayments on the Series B notes are $5 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. The trust indenture governing the Series B notes contains covenants such as requirements to maintain certain financial ratios. Evangeline incurred the subordinated note payable in connection with its acquisition of a contract-based intangible asset in the early 1990s. This note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B note holders are either fully cash secured through debt service accounts or have been completely repaid. In general, interest accrues on the subordinated note at a variable-rate based on LIBOR plus ½%. The variable interest rate paid on this debt at December 31, 2004 was 1.73%.

10. MINORITY INTEREST

Minority interest represents third-party and related party ownership interests in the net assets of certain of our subsidiaries. The following table shows the components of minority interest at December 31, 2004:

EPD’s limited partners:
Non-affiliates of EPGP Members	$ 3,992,153
Affiliates of EPGP Members	802,505
Joint venture partners	71,040
	$ 4,865,698

The minority interest attributable to EPD's limited partners consists of EPD common units held by the public, Shell and affiliates of the Company, which primarily includes EPCO, and is net of unamortized deferred compensation of $10.9 million which represents the value of EPD common units issued to key employees of EPCO. The minority interest attributable to joint venture partners is primarily attributable to our partners in Tri-States, Seminole, Wilprise, Independence Hub and the Mid-America pipeline system. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third-party investor's ownership in our consolidated balance sheet amounts shown as minority interest.

11. CAPITAL STRUCTURE

At December 31, 2004, our members’ equity account balances and ownership interests were as follows:

		Membership
		Percentage
DFI		85.595%	$ 46,106
DDC		4.505%	3,378
El Paso		9.900%	90,845
	Subtotal		140,329
Accumulated Other Comprehensive Income			24,554
	Total		$ 164,883

Earnings and cash distributions are allocated to Member capital accounts in accordance with their respective membership percentages. DFI acquired Shell’s 30% member interest in us on September 12, 2003. On September 30, 2004, El Paso was granted a 9.9% membership interest in the Company in connection with our acquisition of El Paso’s 50% membership interest in GulfTerra GP (see Note 4). In January 2005, Enterprise GP Holdings, L.P., a subsidiary of EPCO, purchased El Paso’s 9.9% membership interest in us (see Note 17). See Note 14 for information regarding our Accumulated Other Comprehensive Income.

12. RELATED PARTY TRANSACTIONS

Relationship with EPCO

We have an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is one of our directors and Chairman. In addition, our executive and other officers are employees of EPCO, including Robert G. Phillips who is our Chief Executive Officer and one of our directors.

On September 30, 2004, we borrowed $370 million from DDC, which owns a 4.5% membership interest in the Company (see Note 9). DDC is wholly owned by Dan L. Duncan. We used the proceeds from this borrowing to fund the cash portion of the consideration paid to El Paso for a 50% membership interest in GulfTerra GP (see Note 4).

Mr. Duncan owns 50.4% of the voting stock of EPCO. The remaining shares of EPCO capital stock are held primarily by trusts for the benefit of members of Mr. Duncan’s family. In addition, at December 31, 2004, EPCO and DDC, together, owned 90.1% of our membership interests. In January 2005, an affiliate of EPCO, Enterprise GP Holdings L.P., acquired El Paso’s 9.9% membership interest in us (see Note 17). As a result of this transaction, EPCO and its affiliates own 100% of our membership interests.

Our agreements with EPCO are not the result of arm’s-length transactions, and there can be no assurance that any of the transactions provided for therein are effected on terms at least as favorable to the parties to such agreement as could have been obtained from unaffiliated third parties.

Administrative Services Agreement. We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. Under the current terms of the Administrative Services Agreement, EPCO agrees to:

•	employ the personnel necessary to manage our business and affairs;

•	employ the operating personnel involved in our business;

•	allow us to participate as named insureds in EPCO’s current insurance program with the costs being allocated among the parties on the basis set forth in the agreement;

•	sublease to the Operating Partnership certain equipment which it holds pursuant to operating leases for one dollar per year and to assign to us its purchase option under such leases (the “retained leases”). EPCO remains liable for the cash lease payments associated with these assets.

The Operating Partnership records the lease payment made by EPCO as a non-cash operating expense offset by a corresponding increase in its partners' equity. As of December 31, 2004, the remaining retained leases were for a cogeneration unit and approximately 100 railcars. During 2004, the Operating Partnership exercised their options to purchase an isomerization unit and related equipment at a cost of $17.8 million. Should the Operating Partnership decide to exercise the purchase options associated with the remaining retained leases (which are also at fair value), an additional $2.3 million would be payable in 2008 and $3.1 million in 2016. In addition to retained lease expenses, operating costs and expenses include compensation charges for EPCO’s employees who operate our facilities.

Prior to January 1, 2004, our payments to EPCO and related non-cash expenses for administrative support were based on the following:

•

We reimbursed EPCO for their share of the costs of certain of its employees in administrative positions that were active at the time of EPD's initial public offering in July 1998 (the “pre-expansion” administrative personnel). Our obligation for reimbursing these costs was covered by the EPCO Administrative Service Fee.

•

To the extent that EPCO’s actual cost of providing the pre-expansion administrative personnel exceeded the Administrative Service Fee charged to us during a given year, we recorded a non-cash expense equal to the difference between EPCO's actual cost and the Administrative Service Fee charged. The offset was recorded in partners' equity as a general contribution to the Operating Partnership.

•	We also reimbursed EPCO for all costs it incurs related to administrative personnel it hires in response to our expansion activities.

Effective January 1, 2004, the Administrative Services Agreement was amended to eliminate the fixed Administrative Services Fee and to provide that the Operating Partnership reimburse EPCO for all costs related to administrative support regardless of whether the costs are related to pre-expansion or expansion personnel who work on our behalf.

On October 22, 2004, the Administrative Services Agreement was amended further to evidence our separateness from other persons and entities, to reflect a five-year license we granted for EPCO’s use of service marks owned by us and to provide for reimbursement of EPCO’s costs of discontinuing the use of those service marks over the term of the license. This amendment also provides that if EPCO and its affiliates are offered by a third party, or discover an opportunity to acquire from a third party, a business or assets that is or are in the same or similar line of business then being conducted by the Operating Partnership or in a line of business that would be a natural extension of any business then being conducted by the Operating Partnership (a “Business Opportunity”), EPCO shall promptly advise our Board of Directors of such Business Opportunity and offer such Business Opportunity to the Operating Partnership. If our Board of Directors does not advise EPCO within 10 days following the receipt of such notice that we wish to pursue such Business Opportunity, EPCO shall then be permitted to pursue such Business Opportunity. If our Board of Directors advises EPCO within such 10 day period that we want to pursue such Business Opportunity, EPCO shall not be permitted to pursue such Business Opportunity unless our Board of Directors subsequently advises EPCO that it has abandoned its pursuit of such Business Opportunity.

Other related party transactions with EPCO. The following is a summary of other significant related party transactions between EPCO and us, including those between EPCO and our unconsolidated affiliates.

•	Prior to January 1, 2004, EPCO was the operator of our MTBE facility and Houston Ship Channel NGL import facility.

•	We have entered into an agreement with EPCO to provide trucking services to us for the transportation of NGLs and other products.


•	In the normal course of business, we also buy from and sell to EPCO’s Canadian affiliate certain NGL products.

We and EPD are separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from EPCO and its other affiliates. EPCO primarily depends on the cash distributions it receives as an equity owner in EPD to fund its other operations and to meet its debt obligations.

Relationship with Shell

We have a significant commercial relationship with Shell as a partner, customer and vendor. At March 15, 2005, Shell owned approximately 9.5% of EPD's common units. In March 2005, EPD registered for resale Shell's 36,572,122 common units under a registration rights agreement EPD executed with Shell in connection with EPD's acquisition of certain of Shell's Gulf Coast midstream energy businesses in September 1999. For additional information regarding this subsequent event, see Note 17. Shell sold its 30.0% interest in us to a subsidiary of EPCO in September 2003.

Shell is one of our largest customers. For the year ended December 31, 2004, Shell accounted for 6.5% of our consolidated revenues. Our revenues from Shell primarily reflect the sale of NGL and petrochemical products to Shell and the fees we charge Shell for natural gas processing, 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 Shell. We also lease from Shell its 45.4% interest in one of our propylene fractionation facilities located in Mont Belvieu, Texas.

The most significant contract affecting our natural gas processing business is the Shell margin-band/keepwhole processing agreement, which grants us the right to process Shell's current and future production within state and federal waters of the Gulf of Mexico. The Shell processing agreement includes a life of lease dedication, which may extend the agreement well beyond its initial 20-year term ending in 2019.

We have also completed a number of business acquisitions and asset purchases involving Shell since 1999, including the acquisition of midstream energy assets located along the Gulf Coast for approximately $528.8 million in 1999; the purchase of the Lou-Tex Propylene pipeline for $100 million in 2000; and the acquisition of the Acadian Gas pipeline system in 2001 for $243.7 million.

Relationships with unconsolidated affiliates

Our investment in unconsolidated affiliates with industry partners is a vital component of our business strategy. These investments are a means by which we conduct our operations to align our interests with 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. The following summarizes significant related party transactions we have with our current unconsolidated affiliates:

•	We sell natural gas to Evangeline, which, in turn, uses the natural gas to satisfy supply commitments it has with a major Louisiana utility. In addition, we have also furnished $11.1 million in letters of credit on behalf of Evangeline.

•	We pay transportation fees to Dixie for propane movements on their system initiated by our NGL marketing activities.

•	We pay Promix for the transportation, storage and fractionation of certain of our mixed NGL volumes. In addition, we sell natural gas to Promix for their fuel requirements.

We enter into management agreements with some of our unconsolidated affiliates under which our unconsolidated affiliates pay us management fees for the operation and management of their assets. Additionally, on occasion we pay for construction costs on behalf of our unconsolidated affiliates during the initial construction

phase of their assets, and these amounts are settled by direct reimbursements for the amounts we are owed from our unconsolidated affiliates.

13. COMMITMENTS AND CONTINGENCIES

Redelivery Commitments

We store and transport NGL, petrochemical and natural gas volumes for third parties under various processing, storage, transportation and similar agreements. Under the terms of these agreements, we are generally required to redeliver volumes to the owner on demand. We are insured for any physical loss of such volumes due to catastrophic events. At December 31, 2004, NGL and petrochemical volumes aggregating 13.5 million barrels were due to be redelivered to their owners along with 18,038 BBtus of natural gas.

Commitments under equity compensation plans of EPCO

In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for EPD (see Note 12). This includes the costs associated with equity-based awards granted to these employees. At December 31, 2004, there were 2,463,000 options outstanding to purchase common units under EPCO’s 1998 Plan that had been granted to employees for which we are responsible for reimbursing EPCO for the costs of such awards. The weighted-average strike price of the unit option awards granted was $18.84 per common unit. At December 31, 2004, 1,154,000 of these unit options were exercisable. An additional 374,000, 25,000 and 910,000 of these unit options will be exercisable in 2005, 2006 and 2008, respectively. As these options are exercised, we will reimburse EPCO in the form of a special cash distribution for the difference between the strike price paid by the employee and the actual purchase price paid for the units awarded to the employee.

Other commitments

The following table summarizes our various contractual obligations at December 31, 2004. A description of each type of contractual obligation follows.

	Payment or Settlement due by Period
Contractual Obligations	Total		2005		2006		2007		2008		2009		Thereafter
Scheduled maturities of long-term debt	$	4,655,131	$	18,450	$	3,802	$	504,045	$	4,242	$	825,576	$	3,299,016

Operating lease obligations	$	88,899	$	15,012	$	13,328	$	12,294	$	9,496	$	5,418	$	33,351

Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	1,160,829	$	165,120	$	142,133	$	142,133	$	142,522	$	142,133	$	426,788
NGLs	$	174,281	$	42,664	$	10,968	$	10,968	$	10,968	$	10,968	$	87,745
Petrochemicals	$	1,791,983	$	1,010,907	$	667,288	$	107,540	$	6,248
Other	$	166,706	$	41,706	$	32,179	$	30,092	$	28,690	$	18,155	$	15,884
Underlying major volume commitments:
Natural gas (in BBtus)		149,705		21,855		18,250		18,250		18,300		18,250		54,800
NGLs (in MBbls)		5,657		1,267		366		366		366		366		2,926
Petrochemicals (in MBbls)		27,294		15,559		10,126		1,520		89

Service payment commitments	$	7,580	$	4,906	$	2,038	$	636
Capital expenditure commitments	$	69,288	$	69,288

Long-term debt-related commitments. We have long and short-term payment obligations under credit agreements such as our Senior Notes and revolving credit facilities. The preceding table shows our scheduled future maturities of long-term debt principal (including current maturities) for the periods indicated. See Note 9 for a description of these debt obligations and classification used for accounting purposes.

Operating lease commitments. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. The preceding table shows the minimum lease payment obligations under our third-party operating leases with terms in excess of one year for the periods indicated.

Our material agreements consist of operating leases, with original terms ranging from 5 to 24 years, for natural gas and NGL underground storage facilities. We generally have the option to renew these leases, under the terms of the agreements, for one or more renewal terms ranging from 2 to 10 years. In general, rent is determined by multiplying a storage quantity (typically in barrels) by a contractually stated price. Rental payments under our storage leases are escalated, as specified in the lease, to reflect increases in the market value of the storage capacity or to adjust for inflation. In general, contingent rental payments are assessed when our storage volumes exceed our storage allotment and are equal to the product of (i) a contractually stated price and (ii) the volume which exceeds our storage allotment.

Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. Under certain of our natural gas and NGL storage lease agreements, we are required to perform routine maintenance on the storage facility. In addition, certain leases give us the option to increase storage capacity or fund major leasehold improvements. Maintenance, repairs and minor renewals are charged to operations as incurred. We have not made any major leasehold improvements with regards to our natural gas and NGL underground storage facilities during the year ended December 31, 2004.

The operating lease commitments shown in the preceding table exclude the non-cash related party expense associated with various equipment leases contributed to us by EPCO at our formation for which EPCO has retained the liability (the “retained leases”). The retained leases are accounted for as operating leases by EPCO. EPCO’s minimum future rental payments under these leases are $2.1 million for each of the years 2005 through 2008, $0.7 million for each of the years 2009 through 2015 and $0.3 million for 2016.

EPCO has assigned to the Operating Partnership the purchase options associated with the retained leases. During 2004 we purchased an isomerization unit and related equipment for $17.8 million pursuant to their purchase options, which prices approximated fair value. Should we decide to exercise all of the remaining purchase options associated with the retained leases (which are also at fair value), up to an additional $2.3 million would be payable in 2008 and $3.1 million in 2016.

Purchase obligations. We define purchase obligations as agreements to purchase goods or services that are enforceable and legally binding (unconditional) and that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have classified our unconditional purchase obligations into the following categories:

•

Product purchase commitments. We have long and short-term product purchase obligations for NGLs, petrochemicals and natural gas with several third-party suppliers. The purchase prices that we are generally obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table shows our volume commitments and estimated payment obligations under these contracts for the periods indicated. At December 31, 2004, we do not have any product purchase commitments with fixed or minimum pricing provisions having remaining terms in excess of one year. To the extent that variable price provisions exist in these contracts, our estimated future payment obligations are based on the contractual price under each contract for purchases made at December 31, 2004 applied to future volume commitments.

•	Service contract commitments. We have long and short-term commitments to pay third-party service providers for services such as maintenance agreements. Our contractual payment obligations vary by contract. The preceding table shows our future payment obligations under these service contracts.

•

Capital expenditure commitments. We have short-term payment obligations relating to capital projects we have initiated and are also responsible for our share of such obligations associated with capital projects of our unconsolidated affiliates. These commitments represent unconditional payment obligations that we or our unconsolidated affiliates have agreed to pay vendors for services rendered or products purchased. The preceding table shows these combined amounts for the periods indicated.

Litigation

We are sometimes named as a defendant in litigation relating to our normal business operations, including litigation related to various federal, state and local regulatory and environmental matters. Although we insure against various business risks, to the extent management believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of ordinary business activity. Management is not aware of any significant litigation, pending or threatened, that would have a significant adverse effect on our financial position or results of operations.

We own a facility that historically produced MTBE, a motor gasoline additive that enhances octane and is used in reformulated motor gasoline. We operated the facility, which is located within our Mont Belvieu complex. The production of MTBE was primarily driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990. In recent years, MTBE has been detected in water supplies. The major source of ground water contamination appears to be leaks from underground storage tanks. As a result of environmental concerns, several states enacted legislation to ban or significantly limit the use of MTBE in motor gasoline within their jurisdictions. In addition, federal legislation has been drafted to ban MTBE and replace the oxygenate with renewable fuels such as ethanol.

A number of lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing MTBE, although generally such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary which owns the facility. It is possible, however, that MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

Performance Guaranty

In December 2004, our Independence Hub, LLC subsidiary entered into the Independence Hub Agreement (the "Agreement") with six oil and natural gas producers. The Agreement obligates Independence Hub, LLC (i) to construct an offshore platform production facility to process 850 MMcf/d of natural gas and condensate and (ii) to process certain natural gas and condensate production of the six producers following construction of the platform facility.

In conjunction with the Agreement, the Operating Partnership guaranteed the performance of its Independence Hub, LLC subsidiary under the Hub Agreement up to $397.5 million. In December 2004, 20% of this guaranteed amount was assumed by Cal Dive, our joint venture partner in the Independence Hub project. The remaining $318 million represents our share of the anticipated cost of the platform facility. This amount represents the cap on the Operating Partnership's potential obligation to the six producers for our share of the cost of constructing the platform in the very unlikely scenario where the six producers take over the construction of the platform facility. The Operating Partnership's performance guarantee continues until the earlier to occur of (i) all of the guaranteed obligations of Independence Hub, LLC shall have been terminated or expired, or shall have been indefeasibly paid or otherwise performed or discharged in full, (ii) upon mutual written consent of the Operating Partnership and the producers or (iii) mechanical completion of the production facility. We expect that mechanical completion will occur on or about November 1, 2006; therefore, we anticipate that the performance guaranty will exist until at least this forecast date.

In accordance with FIN 45, we recorded the fair value of the performance guaranty using an expected present value approach. Given the remote probability that the Operating Partnership would be required to perform under the guaranty, we have estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of current and other long-term liabilities on our Consolidated Balance Sheet at December 31, 2004.

14. FINANCIAL INSTRUMENTS

We are exposed to financial market risks, including changes in commodity prices and interest rates. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to the variability of future earnings, fair values of certain debt instruments and cash flows resulting from changes in applicable interest rates or commodity prices. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.

We recognize financial instruments as assets and liabilities on our Consolidated Balance Sheets based on fair value. Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.

Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings.

To qualify as a hedge, the item to be hedged must be exposed to commodity or interest rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge is recorded in current earnings.

Due to the complexity of SFAS No. 133 (as amended and interpreted), the FASB is continuing to provide guidance regarding the implementation of this accounting standard. Since this guidance is still continuing, our conclusions about the application of SFAS No. 133 may be altered, which may result in adjustments being recorded in future periods as we adopt new FASB interpretations of this standard.

Interest rate risk hedging program

Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We assess the cash flow risk related to interest rates by identifying and measuring changes in our interest rate exposures that may impact future cash flows and evaluating hedging opportunities to manage these risks. We use analytical techniques to measure our exposure to fluctuations in interest rates, including cash flow sensitivity analysis models to forecast the expected impact of changes in interest rates on our future cash flows. Management oversees the strategies associated with these financial risks and approves instruments that are appropriate for our requirements.

We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. We believe that it is prudent to maintain an appropriate balance of variable rate and fixed rate debt in the current business climate.

Fair value hedges – Interest rate swaps. In January 2004, we entered into three interest rate swap agreements with an aggregate notional amount of $250 million in which we exchanged the payment of fixed rate interest on a portion of the principal outstanding under Senior Notes B and C for variable rate interest. During the fourth quarter of 2004, we entered into six additional interest rate swap agreements with an aggregate notional amount of $600 million related to a portion of the principal outstanding under Senior Notes G issued on October 4, 2004.

		Number	Period Covered	Termination	Fixed to	Notional
Hedged Fixed Rate Debt		Of Swaps	by Swap	Date of Swap	Variable Rate ⁽¹⁾	Amount
Senior Notes B, 7.50% fixed rate, due Feb. 2011		1	Jan. 2004 to Feb. 2011	Feb. 2011	7.50% to 6.3%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 4.9%	$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014		6	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.6% to 3.4%	$600 million

	(1) The variable rate indicated is the all-in variable rate for the current settlement period.

We have designated these nine interest rate swaps as fair value hedges under SFAS No. 133 since they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense.

These nine agreements have a combined notional amount of $850 million and match the maturity dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a variable interest rate based on six-month LIBOR rates (plus an applicable margin as defined in each swap agreement) and receive back from the counterparty a fixed interest rate payment based on the stated interest rate of the debt being hedged, with both payments calculated using the notional amounts stated in each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”). The settlement amount is amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.

Total fair value of the interest rate swaps in effect at December 31, 2004 was a receivable of approximately $0.5 million with an offsetting increase in fair value of the underlying debt.

Cash flow hedges – Forward starting interest rate swaps. During the first nine months of 2004, we entered into eight forward starting interest rate swap transactions having an aggregate notional amount of $2 billion in anticipation of our financing activities associated with closing the GulfTerra Merger. Our purpose in entering into these transactions was to effectively hedge the underlying U.S. treasury rate related to our anticipated issuance of $2 billion in principal amount of fixed rate debt. On October 4, 2004, our Operating Partnership issued $2 billion of private debt securities under Senior Notes E, F, G and H. Each of the forward starting swaps was designated as a cash flow hedge under SFAS No. 133.

In April 2004, we elected to terminate the initial four forward starting swaps in order to manage and maximize the value of the swaps and to reduce future debt service costs. As a result, we received $104.5 million in cash from the counterparties. In September 2004, we settled the remaining four swaps resulting in an $85.1 million payment to the counterparties. The net gain of $19.4 million from these settlements will be reclassified from Accumulated Other Comprehensive Income to reduce interest expense over the life of the associated debt.

The following table shows the notional amount covered by each forward starting swap and the cash gain (loss) associated with each swap upon settlement (dollars in thousands):

	Notional	Net Cash
	Amount of	Received upon
	Debt covered by	Settlement of
Term of Anticipated Debt Offering	Forward	Forward
(or Forecasted Transaction)	Starting Swaps	Starting Swaps
3-year, fixed rate debt instrument	$ 500,000	$ 4,613
5-year, fixed rate debt instrument	500,000	7,213
10-year, fixed rate debt instrument	650,000	10,677
30-year, fixed rate debt instrument	350,000	(3,098)
Total	$ 2,000,000	$ 19,405

Commodity risk hedging program

The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with natural gas and NGLs, we may enter into commodity financial instruments. The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas or NGLs. The commodity financial instruments we utilize may be settled in cash or with another financial instrument. Historically, we have not hedged our exposure to risks associated with petrochemical products, including MTBE.

We have adopted a policy to govern our use of commodity financial instruments to manage the risks of our natural gas and NGL businesses. The objective of this policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by the Company. We may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months. Management oversees our strategies associated with physical and financial risks (such as those mentioned previously), approves specific activities subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.

At December 31, 2004, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of natural gas cash flow and fair value hedges. We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific exposure. When this occurs, we may enter into a new commodity financial instrument to reestablish the economic hedge to which the closed instrument relates.

We had a limited number of commodity financial instruments open at December 31, 2004. The fair value of these open positions at December 31, 2004 was an asset of $219 thousand, which amount is based on market prices on that date.

Effect of financial instruments on Accumulated Other Comprehensive Income (Loss)

The following table summarizes the effect of our cash flow hedging financial instruments on accumulated other comprehensive income (loss) since January 1, 2004.

		Interest Rate Fin. Instrs.		Accumulated
			Forward-	Other
	Commodity		Starting	Comprehensive
	Financial	Treasury	Interest	Income (Loss)
	Instruments	Locks	Rate Swaps	Balance
Balance, January 1, 2004		$ 4,990		$ 4,990
Gain on settlement of forward-starting interest rate swaps			$ 104,531	104,531
Loss on settlement of forward-starting interest rate swaps			(85,126)	(85,126)
Change in fair value of commodity financial instrument	$ 1,434			1,434
Reclassification of gain on settlement of treasury locks to interest expense		(418)		(418)
Reclassification of gain on settlement of forward-starting swaps to interest expense			(857)	(857)
Balance, December 31, 2004	$ 1,434	$ 4,572	$ 18,548	$ 24,554

During 2005, we will reclassify $0.4 million and $3.6 million from Accumulated Other Comprehensive Income as a reduction in interest expense from our treasury locks and forward-starting interest rate swaps, respectively. In addition, in the first quarter of 2005, we will record an approximate $1.6 million gain into income from Accumulated Other Comprehensive Income related to a commodity cash flow hedge acquired in the GulfTerra

Merger. This gain is primarily due to an increase in fair value from that recorded for the commodity cash flow hedge at December 31, 2004.

Fair value information

Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair value due to their short-term nature. The estimated fair value of our fixed rate debt is estimated based on quoted market prices for such debt or debt of similar terms and maturities. The carrying amounts of our variable rate debt obligations reasonably approximate their fair values due to their variable interest rates. The fair values associated with our commodity and interest rate hedging financial instruments were developed using available market information and appropriate valuation techniques. The following table summarizes the estimated fair values of our various financial instruments at December 31, 2004:

		Carrying	Fair
Financial Instruments		Value	Value
Financial assets:
	Cash and cash equivalents	$ 51,163	$ 51,163
	Accounts receivable	1,083,526	1,083,526
	Commodity financial instruments ⁽¹⁾	3,904	3,904
	Interest rate hedging financial instruments ⁽²⁾	505	505
Financial liabilities:
	Accounts payable and accrued expenses	1,468,933	1,468,933
	Fixed-rate debt (principal amount)	4,091,902	4,289,084
	Variable-rate debt	563,229	563,229
	Commodity financial instruments ⁽¹⁾	3,685	3,685

(1) Represent commodity financial instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction. (2) Represent interest rate hedging financial instrument transactions that had not settled. Settled transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

Counterparty risk

From time to time, we have credit risk with our counterparties in terms of settlement risk associated with financial instruments. On all transactions where we are exposed to credit risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral and we do not anticipate nonperformance by our counterparties.

15. SEGMENT INFORMATION

Business segments are components of a business about which separate financial information is available. The components are regularly evaluated by our CEO in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments.

As a result of the GulfTerra Merger (see Note 4), we have reorganized our business activities into four reportable business segments, as discussed below. Our business segments are generally organized and managed according to the type of services rendered and products produced and/or sold. We have revised our prior segment information in order to conform to the current business segment operations and presentation.

We have segregated our business activities into four reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services, and Petrochemical Services. Our

business segments are generally organized and managed according to the type of services rendered (or technology or process employed) and products produced and/or sold, as applicable.

The Offshore Pipelines & Services business segment consists of (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 800 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico, which are included in our Offshore Pipelines & Services business segment.

The Onshore Natural Gas Pipelines & Services business segment consists of approximately 17,200 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, this segment includes two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast domestic natural gas markets. This segment also includes leased natural gas storage facilities located in Texas and Louisiana.

The NGL Pipelines & Services business segment includes our (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,775 miles and related storage facilities, which include our strategic Mid-America and Seminole NGL pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes our import and export terminaling operations.

The Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex, and an octane additive production facility. This segment also includes various petrochemical pipeline systems.

The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings we received from GulfTerra GP and our underlying investment in this entity at December 31, 2003. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger. Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours.

Most of our plant-based operations are located either along the western Gulf Coast in Texas, Louisiana and Mississippi or in New Mexico. Our natural gas, NGL and oil pipelines and related operations are in a number of regions of the United States including the Gulf of Mexico offshore Texas and Louisiana; the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and certain regions of the central and western United States. Our marketing activities are headquartered in Houston, Texas at our main office and service customers in a number of regions in the United States including the Gulf Coast, West Coast and Mid-Continent areas.

Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are allocated to each segment on the basis of each asset's or investment's principal operations. The principal reconciling item between consolidated property, plant and equipment and segment assets is construction-in-progress. Segment assets represent those facilities and projects that contribute to gross operating margin and is net of accumulated depreciation on these assets. Since assets under construction generally do not contribute to segment gross operating margin, these assets are excluded from the business segment totals until they are deemed operational. Consolidated intangible assets and goodwill are allocated to each segment based on the classification of the assets to which they relate.

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

	Business Segments
	Offshore Pipeline & Services		Onshore Nat. Gas Pipelines & Services		NGL Pipelines & Services		Petrochem. Services		Non-Segmt. Other	Adjustments and Eliminations		Consolidated Totals
Segment assets:
At December 31, 2004	$	648,181	$	3,729,650	$	2,753,934	$	469,327		$	230,375	$	7,831,467
Investments in and advances
to unconsolidated affiliates:
At December 31, 2004		319,463		5,251		173,883		20,567					519,164
Intangible Assets:
At December 31, 2004		200,047		425,806		303,459		51,289					980,601
Goodwill:
At December 31, 2004		62,348		290,397		32,763		73,690					459,198

In general, our historical financial position has been affected by numerous acquisitions since 2002. Our most significant transaction to date was the GulfTerra Merger, which was completed on September 30, 2004. The aggregate value of the total consideration we paid or issued to complete the GulfTerra Merger was approximately $4 billion. For information regarding our business combinations, see Note 4.

16. CONDENSED FINANCIAL INFORMATION OF OPERATING PARTNERSHIP

The Operating Partnership and its subsidiaries conduct substantially all of our business. Currently, neither we nor EPD have any independent operations or material assets outside of those of the Operating Partnership.

At December 31, 2004, the Operating Partnership had $3.7 billion in outstanding debt securities represented by its Senior Notes A through H. EPD acts as guarantor of all of the Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes and the remaining amounts outstanding under GulfTerra’s senior and senior subordinated notes. If the Operating Partnership were to default on any debt EPD guarantees, EPD would be responsible for full repayment of that obligation. EPD's guarantee of these debt obligations is full and unconditional. These debt obligations are non-recourse to us. For additional information regarding our consolidated debt obligations, see Note 9.

The number and dollar amounts of reconciling items between EPD's consolidated financial statements and those of its Operating Partnership are insignificant. The primary reconciling items between the consolidated balance sheet of the Operating Partnership and EPD's consolidated balance sheet are treasury units EPD owns directly and minority interest.

The following table shows condensed consolidated balance sheet data for the Operating Partnership at December 31, 2004:

ASSETS
Current assets		$ 1,425,574
Property, plant and equipment, net		7,831,467
Investments in and advances to unconsolidated affiliates, net		519,164
Intangible assets, net		980,601
Goodwill		459,198
Deferred tax asset		6,467
Long-term receivables		14,931
Other assets		43,208
	Total	$ 11,280,610
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		$ 1,582,911
Long-term debt		4,266,236
Other long-term liabilities		63,521
Minority interest		73,858
Partners' equity		5,294,084
	Total	$ 11,280,610

Total Operating Partnership debt obligations guaranteed by EPD		$ 4,267,229

17. SUBSEQUENT EVENTS

January 2005 acquisition of El Paso’s interests in EPD and EPGP by affiliates of EPCO

In January 2005, an affiliate of EPCO, acquired El Paso’s 9.9% membership interest in EPGP and 13,454,499 of EPD's common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and affiliates own 100% of the membership interests of EPGP and, at March 15, 2005, approximately 38.3% of EPD's total common units outstanding. El Paso no longer owns any interest in EPD or EPGP.

February 2005 EPD equity offering

In February 2005, EPD sold 17,250,000 common units (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005) to the public at an offering price of $27.05 per unit. Net proceeds from this offering, including EPGP’s proportionate net capital contribution of $9.1 million, were approximately $456.5 million after deducting applicable underwriting discounts, commissions and estimated offering expenses of $19.7 million. The net proceeds from this offering, including EPGP’s proportionate net capital contribution, were used to repay our 364-Day Acquisition Credit Facility, to temporarily reduce indebtedness outstanding under our Multi-Year Revolving Credit Facility and for general partnership purposes.

February 2005 EPD private senior notes offering

On February 15, 2005, the Operating Partnership sold $500 million in principal amount of senior notes in a Rule 144A private placement offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes ("Senior Notes I") were issued at 99.379% of their principal amount and have fixed-rate interest of 5.00% and a maturity date of March 1, 2015. The 30-year notes ("Senior Note J") were issued at 98.691% of their principal amount and have fixed-rate interest of 5.75% and a maturity date of March 1, 2035. The Operating Partnership used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A which was on March 15, 2005 and the remaining proceeds for general partnership purposes, including the temporary repayment of indebtedness outstanding under the Multi-Year Revolving Credit Facility.

March 2005 EPD universal shelf registration statement

In March 2005, EPD filed a universal shelf registration statement with the SEC registering the issuance of $4 billion of partnership equity and public debt obligations. In connection with this registration statement, EPD also registered for resale 36,572,122 common units currently owned by Shell and 4,427,878 common units that had been sold by Shell to Kayne Anderson MLP Investment Company in December 2004. EPD is obligated to register the resale of these common units under a registration rights agreement we executed with Shell in connection with our acquisition of certain of Shell's Gulf Coast midstream energy businesses in September 1999.

Non-Public Investigation by the Bureau of Competition of the Federal Trade Commission

On February 24, 2005, an affiliate of EPCO, Enterprise GP Holdings, L.P., acquired TEPPCO GP from Duke Energy Field Services, LLC. TEPPCO GP owns a 2% general partner interest in and is the general partner of TEPPCO. On March 11, 2005, the Bureau of Competition of the Federal Trade Commission delivered written notice to Enterprise GP Holdings, L.P.'s legal advisor that it was conducting a non-public investigation to determine whether Enterprise GP Holdings' acquisition of TEPPCO GP may substantially lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with Enterprise GP Holdings' purchase of TEPPCO GP. EPCO and its affiliates may receive similar inquiries from other regulatory authorities. EPCO and its affiliates, including us, intend to cooperate fully with any such investigations and inquiries.

Item 9.01.

FINANCIAL STATEMENTS AND EXHIBITS.

(c)

Exhibits.

23.1	Consent of Deloitte & Touche LLP.

SIGNATURES

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

ENTERPRISE PRODUCTS PARTNERS L.P.

By:	Enterprise Products GP, LLC, as general partner

Date: March 31, 2005	By:	___/s/ Michael J. Knesek________________
			Michael J. Knesek
			Senior Vice President, Controller, and
			Principal Accounting Officer of
			Enterprise Products GP, LLC

EXHIBIT INDEX

Exhibit No.	Exhibit
23.1	Consent of Deloitte & Touche LLP.

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

FORM 8-K

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

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

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