Enterprise Products Partners (EPD) 8-K Other Events

EXHIBIT 99.1

Enterprise Products GP, LLC

Consolidated Balance Sheet at December 31, 2005

and Report of Independent Registered Public Accounting Firm

ENTERPRISE PRODUCTS GP, LLC

TABLE OF CONTENTS

		Page No.
Report of Independent Registered Public Accounting Firm		2
Consolidated Balance Sheet as of December 31, 2005		3
Notes to Consolidated Balance Sheet
	Note 1 – Company Organization and Basis of Financial Statement Presentation	4
	Note 2 – Summary of Significant Accounting Policies	5
	Note 3 – Recent Accounting Developments	9
	Note 4 – Employee Benefit Plans	10
	Note 5 – Financial Instruments	11
	Note 6 – Inventories	14
	Note 7 – Property, Plant and Equipment	15
	Note 8 – Investments in and Advances to Unconsolidated Affiliates	16
	Note 9 – Business Combinations and Other Acquisitions	19
	Note 10 – Intangible Assets and Goodwill	21
	Note 11 – Debt Obligations	23
	Note 12 – Minority Interest	27
	Note 13 – Member's Equity	28
	Note 14 – Business Segments	29
	Note 15 – Related Party Transactions	30
	Note 16 – Income Taxes for Certain Pipeline Operations	35
	Note 17 – Commitments and Contingencies	36
	Note 18 – Significant Risks and Uncertainties	38
	Note 19 – Condensed Financial Information of Operating Partnership	40

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2005. 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, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 27, 2006

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ENTERPRISE PRODUCTS GP, LLC

CONSOLIDATED BALANCE SHEET

AT DECEMBER 31, 2005

(Dollars in thousands)

ASSETS
Current assets
	Cash and cash equivalents			$          42,141
	Restricted cash			14,952
	Accounts and notes receivable - trade, net of allowance
		for doubtful accounts of $25,849		1,448,026
	Accounts receivable - related parties			5,534
	Inventories			339,606
	Prepaid and other current assets			120,208
			Total current assets	1,970,467
Property, plant and equipment, net				8,689,024
Investments in and advances to unconsolidated affiliates				471,921
Intangible assets, net of accumulated amortization of $163,121				913,626
Goodwill				494,033
Deferred tax asset				3,606
Other assets				47,359
			Total assets	$   12,590,036
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
	Accounts payable - trade			$        265,699
	Accounts payable - related parties			23,367
	Accrued gas payables			1,372,837
	Accrued expenses			30,294
	Accrued interest			71,193
	Other current liabilities			127,332
			Total current liabilities	1,890,722
Long-term debt				4,833,781
Other long-term liabilities				84,594
Minority interest				5,246,789
Commitments and contingencies
Member's equity				534,150
			Total liabilities and member's equity	$   12,590,036

See Notes to Consolidated Balance Sheet.

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ENTERPRISE PRODUCTS GP, LLC

NOTES TO CONSOLIDATED BALANCE SHEET

AT DECEMBER 31, 2005

1. Company Organizationand Basis of Financial Statement Presentation

Significant relationships referenced in Notes to Consolidated Balance Sheet

Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise Products GP, LLC” are intended to mean and include the business and operations of Enterprise Products GP, LLC, as well as its consolidated subsidiaries, which include Enterprise Products Partners L.P. and its consolidated subsidiaries.

References to “Enterprise Products GP” are intended to mean and include Enterprise Products GP, LLC, individually as the general partner of Enterprise Products Partners L.P., and not on a consolidated basis.

References to “Enterprise Products Partners” mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries.

References to the “Operating Partnership” mean the business and operations of Enterprise Products Operating L.P. and its consolidated subsidiaries.

References to the “Enterprise GP Holdings” are intended to mean Enterprise GP Holdings L.P., individually as our parent company, and not on a consolidated basis.

References to “EPCO” mean EPCO, Inc., which is a related party affiliate to all of the foregoing named entities. Additionally, all of the foregoing named entities are affiliates and under common control of Dan L. Duncan, the Chairman and the controlling shareholder of EPCO.

Company organization and formation

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

In August 2005, Duncan Family Interests, Inc., Dan Duncan, LLC and DFI GP Holdings L.P. (formerly our “Members”) contributed their membership interests in Enterprise Products GP to Enterprise GP Holdings. As a result of this contribution, Enterprise GP Holdings owns 100% of the membership interests in Enterprise Products GP. Enterprise GP Holdings is publicly traded partnership, the common units of which are listed on the NYSE under the ticker symbol “EPE.” For additional information regarding the contribution of membership interests in Enterprise Products GP to Enterprise GP Holdings, please see Note 13.

In September 2004, we completed the “GulfTerra Merger” transactions, whereby, among other transactions, GulfTerra Energy Partners L.P. (“GulfTerra”) merged with one of our wholly owned subsidiaries. As a result of the GulfTerra Merger, GulfTerra and its subsidiaries and GulfTerra’s general partner (“GulfTerra GP”) became our wholly owned subsidiaries. The GulfTerra Merger greatly expanded our asset base to include numerous natural gas and crude oil pipelines, offshore platforms and other midstream energy assets. Additionally, the GulfTerra Merger included the purchase of various midstream assets from El Paso Corporation (“El Paso”) that are located in South Texas (the “STMA” acquisition).

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Basis of presentation

We own a 2% general partner interest in Enterprise Products Partners, which conducts substantially all of our business. We have no independent operations and no material assets outside those of Enterprise Products Partners. The number of reconciling items between our consolidated balance sheet and that of Enterprise Products Partners are few. The most significant difference is that relating to minority interest ownership in our net assets by the limited partners of Enterprise Products Partners, and the elimination of our investment in Enterprise Products Partners with our underlying partner’s capital account in Enterprise Products Partners. See Note 12 for additional information regarding minority interest in our consolidated subsidiaries.

2. Summary of Significant Accounting Policies

Allowance for Doubtful Accounts

Our allowance for doubtful accounts amount is generally determined based on specific identification and estimates of future uncollectible accounts. Our procedure for recording an allowance for doubtful accounts is based on (i) our historical experience, (ii) the financial stability of our customers and (iii) the levels of credit granted to customers. In addition, we may also increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and those experiencing other financial difficulties. We routinely review our estimates in this area to ascertain that we have recorded sufficient reserves to cover potential losses. Our allowance for doubtful accounts was $25.8 million at December 31, 2005.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.

Consolidation Policy

Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all material intercompany accounts and transactions. We consolidate majority-owned subsidiaries in which we possess a controlling financial interest through a direct or indirect ownership of a majority voting interest in the subsidiary.

We consolidated the balance sheet of Enterprise Products Partners with that of Enterprise Products GP. This accounting consolidation is required because we own 100% of the general partnership interest in Enterprise Products Partners, which gives Enterprise Products GP the ability to exercise control over Enterprise Products Partners.

Investments in which we own 3% to 50% and exercise significant influence over operating and financial policies are accounted for using the equity method. If the investee is organized as a limited liability company and maintains separate ownership accounts for its members, we account for our investment using the equity method if our ownership interest is between 3% and 50%. For all other types of investees, we apply the equity method of accounting if our ownership interest is between 20% and 50%. Our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates are eliminated in consolidation to the extent such amounts are material and remain on our or our equity method investees’ balance sheet in inventory or similar accounts.

If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

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Contingencies

Certain conditions may exist as of the date our consolidated balance sheet was issued, which may result in a loss to the Company but which will only be resolved when one or more future events occur or fail to occur. Our management and its legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our legal counsel evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed.

Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.

Deferred Revenues

We recognize revenues when earned. Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue.

Dollar Amounts

Except as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

Environmental Costs

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s estimate of the ultimate cost to remediate the site. An environmental liability estimate of $21 million for remediation costs associated with mercury gas meters is included in other long-term liabilities on our Consolidated Balance Sheet at December 31, 2005.

Estimates

Preparing Enterprise Products GP’s Consolidated Balance Sheet in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the balance sheet. Our actual results could differ from these estimates.

Exchange Contracts

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.

Receivables and payables arising from exchange transactions are satisfied with products rather than cash. When monetary consideration is required for product differentials and service costs such items are recognized on a net basis.

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Financial Instruments

We use financial instruments such as swaps, forward and other contracts to manage price risks associated with inventories, firm commitments, interest rates and certain anticipated transactions. 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 instrument meets the criteria of a fair value hedge, gains and losses from the instrument will be recorded on the income statement to offset corresponding losses and gains of the hedged item. If the financial instrument meets the criteria of a cash flow hedge, gains and losses from the instrument are recorded in other comprehensive income. Gains and losses on cash flow hedges are reclassified from other comprehensive income to earnings when the forecasted transaction occurs or, as appropriate, over the economic life of the underlying asset. 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 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We 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 immediately recognized in earnings. See Note 5 for a further discussion of our financial instruments.

Impairment Testing for Goodwill

Our goodwill amounts are assessed for recoverability (i) on an annual basis during the second quarter of each year or (ii) on an interim basis when impairment indicators are present. If such indicators are present (e.g., loss of a significant customer, economic obsolescence of plant assets, etc.), the fair value of the reporting unit to which the goodwill is assigned will be calculated and compared to its book value.

If the fair value of the reporting unit exceeds its book value, the goodwill amount is not considered to be impaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value, a charge to earnings is recorded to adjust the carrying value of the goodwill to its implied fair value. See Note 10 for a further discussion of our goodwill.

Impairment Testing for Long-Lived Assets

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 such assets may not be recoverable.

Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values in accordance with SFAS 144. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of 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, a non-cash asset impairment charge is recognized equal to the excess of the asset’s carrying value over its fair value. Fair value is defined as the amount at which an asset or liability could be bought or settled in an arm’s-length transaction. We measure fair value using market prices or, in the absence of such data, appropriate valuation techniques.

Impairment Testing for Unconsolidated Affiliates

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

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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.

Income taxes

Our limited liability company structure is not subject to federal income taxes. As a result, our earnings or losses for federal income tax purposes are included in the tax returns of our individual members. We are organized as a pass-through entity for federal income tax purposes. As a result, our members are individually responsible for the federal income tax on their allocable share of our taxable income.

Income taxes are primarily applicable to certain federal and state tax obligations related to our Seminole Pipeline and Dixie Pipeline. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. See Note 16 for additional information regarding income taxes for certain pipeline operations.

Inventories

Our inventories primarily consist of NGL, petrochemical and natural gas volumes and are valued at the lower of average cost or market. We capitalize as a cost of inventory shipping and handling charges directly related to volumes we (i) purchase from third parties or (ii) take title to in connection with processing or other agreements. As these volumes are sold and delivered out of inventory, the average cost of these products (which includes capitalized freight-in charges) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 6 for a further discussion of our inventories.

Minority Interest

Minority interest represents third-party ownership interests in the net assets of our subsidiaries that primarily include the limited partners of Enterprise Products Partners and our joint ventures. 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 interest in our consolidated balance amounts shown as minority interest.

At December 31, 2005, our joint venture subsidiaries were Seminole Pipeline Company (“Seminole”), Tri-States Pipeline LLC (“Tri-States”), Independence Hub, LLC (“Independence Hub”), Dixie Pipeline Company (“Dixie”) and Belle Rose NGL Pipeline LLC (“Belle Rose”). See Note 12 for additional information regarding minority interest in our consolidated subsidiaries.

Natural Gas Imbalances

Natural gas imbalances result when a customer injects more or less gas into a pipeline than they withdraw. In general, we value our imbalance receivables and payables using a twelve-month moving average of natural gas prices. We believe this valuation method is appropriate given that actual settlement dates may vary by customer. Changes in natural gas prices may impact our estimates.

At December 31, 2005, our imbalance receivables were $89.4 million and are reflected as a component of “Accounts receivable – trade” on our Consolidated Balance Sheet. At December 31, 2005, our imbalance payables were $80.5 million, and are reflected as a component of “Accrued gas payables” on our Consolidated Balance Sheet.

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Property, Plant and Equipment

Property, plant and equipment is recorded at cost. Expenditures for major additions and improvements are capitalized and minor replacements, maintenance, and repairs are charged to expense as incurred. When property and equipment are retired or otherwise disposed of, the cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is included in the results of operations from the respective period. Depreciation is recorded over the estimated useful lives of the related assets primarily using the straight-line method for financial statement purposes. We use other depreciation methods (generally accelerated) for tax purposes where appropriate. See Note 7 for additional information regarding our property, plant and equipment.

Certain of our plant operations entail periodic planned outages for major maintenance activities. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services and related items. We use the expense-as-incurred method for our planned major maintenance activities.

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from its acquisition, construction, development and/or normal operation. We record a liability for AROs when incurred and capitalize an increase in the carrying value 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 its useful life. We will either settle our ARO obligations at the recorded amount or incur a gain or loss upon settlement.

Restricted Cash

Restricted cash represents amounts held by a brokerage firm in connection with (i) our commodity financial instruments portfolio and (ii) physical natural gas purchases made on the NYMEX exchange.

3. Recent Accounting Developments

The following information summarizes recently issued accounting guidance that will (or may) affect our consolidated balance sheet in the future:

• SFAS 123(R), “Share-Based Payment,” eliminates the ability to account for share-based compensation transactions using APB 25 and generally requires instead that such transactions be accounted for using a fair value method. Historically, we have accounted for our share-based transactions using APB 25. We adopted SFAS 123(R) on January 1, 2006.

• SFAS 154, “Accounting Changes and Error Corrections,” provides guidance on the accounting for and reporting of accounting changes and error corrections. We adopted SFAS 154 on January 1, 2006.

• Emerging Issues Task Force (“EITF”) 04-13, “Accounting for Purchases and Sale of Inventory With the Same Counterparty,” requires that two or more inventory transactions with the same counterparty should be viewed as a single nonmonetary transaction, if the transactions were entered into in contemplation of one another. Exchanges of inventory between entities in the same line of business should be accounted for at fair value or recorded at carrying amounts, depending on the classification of such inventory. We are still evaluating this recent guidance, which is effective April 1, 2006 for our partnership, but we do not believe that our revenues or costs and expenses will be materially affected.

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4. Employee Benefit Plans

During the first quarter of 2005, we acquired a controlling ownership interest in Dixie Pipeline Company (“Dixie”), which resulted in Dixie becoming a consolidated subsidiary of ours. Dixie employs the personnel that operate its pipeline system and certain of these employees are eligible to participate in a defined contribution plan and pension and postretirement benefit plans. Due to the immaterial nature of Dixie’s employee benefit plans to our consolidated financial position, our discussion is limited to the following:

Defined contribution plan.Dixie contributed $0.3 million to its company-sponsored defined contribution plan during 2005.

Pension and postretirement benefit plans.Dixie’s pension plan is a noncontributory defined benefit plan that provides for the payment of benefits to retirees based on their age at retirement, years of service and average compensation. Dixie’s postretirement benefit plan also provides medical and life insurance to retired employees. The medical plan is contributory and the life insurance plan is noncontributory. Dixie employees hired after July 1, 2004 are not eligible for pension and other benefit plans after retirement.

The following table shows Dixie’s benefit obligations, fair value of plan assets, unfunded liabilities and accrued benefit liabilities at December 31, 2005.

	Pension	Postretirement
	Plan	Plan
Projected benefit obligation	$      9,434	$      4,505
Accumulated benefit obligation	7,023	4,505
Fair value of plan assets	4,954
Unfunded liability	4,480	4,505
Accrued benefit liability	4,348	4,747

Dixie’s net pension and postretirement benefit costs for 2005 were $0.6 million and $0.2 million, respectively. Projected benefit obligations and net periodic benefit costs are based on actuarial estimates and assumptions. The weighted-average actuarial assumptions used in determining net periodic benefit costs for 2005 were as follows: discount rate of 5.75%; expected long-term return on plan assets of 7%; rate of compensation increase of 4%; and a medical trend rate of 7% in 2005 grading to an ultimate trend of rate of 5% in 2007 and later years. The weighted-average actuarial assumptions used in determining the projected benefit obligation at December 31, 2005 were as follows: discount rate of 5.5%, expected long-term rate of return on assets of 7%; rate of compensation increase of 4%; and a medical trend rate of 6% for 2006 grading to an ultimate trend of 5% for 2007 and later years.

Future benefits expected to be paid from Dixie's pension and postretirement plans are as follows for the periods indicated:

	Pension	Postretirement
	Plan	Plan
2006	$       448	$       272
2007	682	289
2008	558	283
2009	800	302
2010	832	330
2011 through 2015	4,804	1,883
Total	$    8,124	$    3,359

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5. 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 Sheet 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 133, (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.

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 financial instrument to reestablish the economic hedge to which the closed instrument relates.

Interest Rate Risk Hedging Program

Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We assess 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 environment.

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As summarized in the following table, we had eleven interest rate swap agreements outstanding at December 31, 2005 that were accounted for as fair value hedges.

		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 7.26%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013		2	Jan. 2004 to Feb. 2013	Feb. 2013	6.375% to 5.8%	$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014		6	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.6% to 5.24%	$600 million
Senior Notes K, 4.95% fixed rate, due June 2010		2	Aug. 2005 to June 2010	June 2010	4.95% to 4.99%	$200 million
	(1) The variable rate indicated is the all-in variable rate for the current settlement period.

We have designated these interest rate swaps as fair value hedges under SFAS 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 the fair value of the underlying hedged debt.

These eleven agreements have a combined notional amount of $1.1 billion 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 London interbank offered rate (“LIBOR”) (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 total fair value of these eleven interest rate swaps at December 31, 2005, was a liability of $19.2 million, with an offsetting decrease in the fair value of the underlying debt.

During the first nine months of 2004, we entered into eight forward starting interest rate swaps having an aggregate notional value of $2 billion in anticipation of our financing activities associated with closing the GulfTerra Merger. Our purpose in entering into these financial instruments was to effectively hedge the underlying U.S. treasury rate related to our issuance of $2 billion in principal amount of fixed-rate debt. In October 2004, the Operating Partnership issued $2 billion of private placement debt under Senior Notes E through H. Each of the forward starting swaps was designated as a cash flow hedge under SFAS 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 following table shows the notional amount covered by each forward starting swap and the cash gain (loss) associated with each swap upon settlement:

	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

The net gain of $19.4 million from these settlements will be reclassified from Accumulated Other Comprehensive Income (“AOCI”) to reduce interest expense over the life of the associated debt. We

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reclassified $4 million from AOCI during 2005, which reduced the amount of interest expense we recognized.

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 our management. 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. Our management oversees the 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, 2005, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of economic hedges. The fair value of our commodity financial instrument portfolio at December 31, 2005 was a liability of $0.1 million.

Fair value information

Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair values due to their short-term nature. The estimated fair values of our fixed rate debt are 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 interest rate and commodity hedging portfolios were developed using available market information and appropriate valuation techniques.

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The following table presents the estimated fair values of our financial instruments at December 31, 2005:

		Carrying	Fair
Financial Instruments		Value	Value
Financial assets:
	Cash and cash equivalents	$         57,093	$         57,093
	Accounts receivable	1,453,560	1,453,560
	Commodity financial instruments (1)	1,114	1,114
	Interest rate hedging financial instruments (2)
Financial liabilities:
	Accounts payable and accrued expenses	1,763,390	1,763,390
	Fixed-rate debt (principal amount)	4,359,068	4,395,110
	Variable-rate debt	507,000	507,000
	Commodity financial instruments (1)	1,167	1,167
	Interest rate hedging financial instruments (2)	19,179	19,179
(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 have not settled. Settled transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

6. Inventories

Our inventory amounts were as follows at December 31, 2005:

Working inventory	$    279,237
Forward-sales inventory	60,369
Inventory	$    339,606

A general description of our inventories is as follows:

• Our regular trade (or “working”) inventory is primarily 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 Oil Price Information Service (“OPIS”) and Chemical Market Associates, Inc. (“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.

Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes and other related costs including terminal and storage fees, vessel inspection and demurrage charges and processing costs.

In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties), these volumes are valued at market-related prices during the month in which they are acquired. As with inventory volumes we purchase for cash, we capitalize as a component of inventory those ancillary costs (e.g. freight-in and other handling and processing charges) incurred in connection with volumes obtained through such contracts.

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Due to fluctuating market conditions in the NGL, natural gas and petrochemical industry, our inventory balances are subject to lower of average cost or market (“LCM”) adjustments when the cost of our inventories exceed their net realizable value.

7. Property, Plant and Equipment

Our property, plant and equipment values and accumulated depreciation balances were as follows at December 31, 2005:

	Estimated
	Useful Life
	in Years
Plants and pipelines (1)	5-35 (5)	$    8,209,580
Underground and other storage facilities (2)	5-35 (6)	549,923
Platforms and facilities (3)	23-31	161,807
Transportation equipment (4)	3-10	24,939
Land		38,757
Construction in progress		854,595
Total		9,839,601
Less accumulated depreciation		1,150,577
Property, plant and equipment, net		$    8,689,024
(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).

We capitalized $22 million of interest associated with construction projects during 2005.

Asset retirement obligations. We have recorded asset retirement obligations related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. In general, our asset retirement obligations primarily result from (i) right-of-way agreements associated with our pipeline operations, (ii) leases of plant sites and (iii) regulatory requirements triggered by the abandonment or retirement of certain underground storage assets and offshore facilities. In addition, our asset retirement obligations may result from the renovation or demolition of certain assets containing hazardous substances such as asbestos.

Previously, we recorded asset retirement obligations associated with the future retirement and removal activities of certain offshore assets located in the Gulf of Mexico. In December 2005, we adopted FIN 47 and recorded an additional $10.1 million in connection with conditional asset retirement obligations. None of our assets are legally restricted for purposes of settling asset retirement obligations.

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The following table presents information regarding our asset retirement obligations since January 1, 2005.

Asset retirement obligation liability balance, January 1, 2005	$      6,236
Adoption of FIN 47 for conditional obligations	10,076
Accretion expense	483
Asset retirement obligation liability balance, December 31, 2005	$    16,795

Property, plant and equipment at December 31, 2005 includes $0.9 million of asset retirement costs capitalized as an increase in the associated long-lived asset.

Certain of our unconsolidated affiliates have AROs recorded at December 31, 2005 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Consolidated Balance Sheet.

8. Investments in and Advances to Unconsolidated Affiliates

Our investments in and advances to our unconsolidated affiliates are grouped according to the business segment to which they relate. For a general discussion of our business segments, see Note 14. The following table shows our ownership percentage and investments in and advances to unconsolidated affiliates at December 31, 2005:

		Ownership	Investments in
		Percentage	and Advances to
NGL Pipelines & Services:
	Venice Energy Services Company, LLC (“VESCO”)	13.1%	$      39,689
	K/D/S Promix LLC (“Promix”)	50%	65,103
	Baton Rouge Fractionators LLC (“BRF”)	32.3%	25,584
Onshore Natural Gas Pipelines & Services:
	Evangeline (1)	49.5%	3,151
	Coyote Gas Treating, LLC (“Coyote”)	50%	1,493
Offshore Pipelines & Services:
	Poseidon Oil Pipeline, L.L.C. (“Poseidon”)	36%	62,918
	Cameron Highway Oil Pipeline Company (“Cameron Highway”) (2)	50%	58,207
	Deepwater Gateway, L.L.C. (“Deepwater Gateway”) (3)	50%	115,477
	Neptune Pipeline Company, L.L.C. (“Neptune”)	25.67%	68,085
	Nemo Gathering Company, LLC (“Nemo”)	33.92%	12,157
Petrochemical Services:
	Baton Rouge Propylene Concentrator, LLC (“BRPC”)	30%	15,212
	La Porte (4)	50%	4,845
Total			$    471,921
(1)    Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2)    Cameron Highway began deliveries of Gulf of Mexico crude oil production to major refining markets along the Texas Gulf Coast during the first quarter of 2005. In June 2005, we received a $47.5 million return of our investment in Cameron Highway due to the refinancing of Cameron Highway’s project debt. For additional information regarding the refinancing of Cameron Highway's debt, please read Note 11. (3)    In March 2005, we contributed $72 million to Deepwater Gateway to fund our share of the repayment of its $144 million term loan. For additional information regarding Deepwater Gateway's repayment of its term loan, please read Note 11. (4)    Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

On occasion, the price we pay to acquire an ownership interest in an investee exceeds the carrying value of the historical net assets of the investee we are purchasing. Such excess amounts (or “excess costs”) are a component of our investments in and advances to unconsolidated affiliates.

At December 31, 2005, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost amounts. At the time of purchase, an analysis of each of these investments indicated that such excess cost amounts were attributable to either (i) an increase in the fair

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value of tangible or qualifying intangible assets owned by each entity over its historical carrying values for such assets or (ii) it was unattributable and deemed to be goodwill. At December 31, 2005, our investments in and advances to unconsolidated affiliates included $48.1 million of excess cost amounts, all of which were attributed to increases in fair value of the underlying assets of the investees.

NGL Pipelines & Services

At December 31, 2005, our NGL Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

VESCO. We own a 13.1% interest in VESCO, which owns a natural gas processing and NGL fractionation facility and related storage and pipeline assets located in south Louisiana. 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.

Promix. We own a 50% interest in Promix, which owns an NGL fractionation facility and related storage and pipeline assets located in south Louisiana.

BRF. We own an approximate 32.3% interest in BRF, which owns an NGL fractionation facility located in south Louisiana.

The combined balance sheet information at December 31, 2005 of this segment’s current unconsolidated affiliates is summarized as follows:

Current assets		$      72,784
Property, plant and equipment, net		328,270
Other assets		12,471
	Total assets	$    413,525
Current liabilities		$      32,886
Other liabilities		7,343
Combined equity		373,296
	Total liabilities and combined equity	$    413,525

Onshore Natural Gas Pipelines & Services

At December 31, 2005, our Onshore Natural Gas Pipelines & Servicessegment included the following unconsolidated affiliates accounted for using the equity method:

Evangeline. We own an approximate 49.5% aggregate interest in Evangeline, which owns a natural gas pipeline system located in south Louisiana.

Coyote. We own 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 at December 31, 2005 of this segment’s current unconsolidated affiliates is summarized as follows:

Current assets		$      41,674
Property, plant and equipment, net		36,380
Other assets		28,732
	Total assets	$    106,786
Current liabilities		$      72,441
Other liabilities		32,737
Combined equity		1,608
	Total liabilities and combined equity	$    106,786

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Offshore Pipelines & Services

At December 31, 2005, our Offshore Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

Poseidon. We own a 36% interest in Poseidon, which owns a crude oil pipeline that gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico for delivery to onshore locations in south Louisiana.

Cameron Highway. We own a 50% interest in Cameron Highway, which owns a crude oil pipeline that gathers production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in southeast Texas. The Cameron Highway Oil Pipeline commenced operations during the first quarter of 2005.

Deepwater Gateway. We own a 50% interest in Deepwater Gateway, which owns the Marco Polo platform located in Green Canyon Block 608 of the Gulf of Mexico. The Marco Polo platform processes crude oil and natural gas production from the Marco Polo, K2, K2 North and Genghis Khan fields located in the South Green Canyon area of the Gulf of Mexico.

Neptune. We own a 25.7% interest in Neptune, which owns the Manta Ray Offshore Gathering System and Nautilus System, which are natural gas pipelines located in the Gulf of Mexico.

Nemo. We own a 33.9% interest in Nemo, which owns the Nemo Gathering System, which is a natural gas pipeline located in the Gulf of Mexico.

The combined balance sheet information at December 31, 2005 of this segment’s current unconsolidated affiliates is summarized as follows:

Current assets		$       141,756
Property, plant and equipment, net		1,201,926
Other assets		7,961
	Total assets	$    1,351,643
Current liabilities		$       120,611
Other liabilities		511,633
Combined equity		719,399
	Total liabilities and combined equity	$    1,351,643

Petrochemical Services

At December 31, 2005, our Petrochemical Services segment included the following unconsolidated affiliates accounted for using the equity method:

BRPC. We own a 30% interest in BRPC, which owns a propylene fractionation facility located in south Louisiana.

La Porte. We own an aggregate 50% interest in La Porte, which owns a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas.

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The combined balance sheet information at December 31, 2005 of this segment’s current unconsolidated affiliates is summarized as follows:

Current assets		$      5,508
Property, plant and equipment, net		54,751
	Total assets	$    60,259
Current liabilities		$      1,178
Other liabilities		1
Combined equity		59,080
	Total liabilities and combined equity	$    60,259

9. Business Combinations and Other Acquisitions

Our expenditures for business combinations and acquisitions during 2005 were $326.6 million, which included $8.3 million of purchase price adjustments relating to transactions that occurred prior to 2005.

In January 2005, we acquired indirect ownership interests in the Indian Springs Gathering System and Indian Springs natural gas processing plant for $74.9 million. In January and February 2005, we acquired an additional 46% of the ownership interests in Dixie for $68.6 million. In June 2005, we acquired additional indirect ownership interests in our Mid-America Pipeline System and Seminole Pipeline for $25 million. Also in June 2005, we acquired an additional 41.7% ownership interest in Belle Rose, which owns a NGL pipeline located in Louisiana, for $4.4 million. In July 2005, we purchased three underground NGL storage facilities and four propane terminals from Ferrellgas L.P. (“Ferrellgas”) for $145.5 million in cash. Dixie and Belle Rose became consolidated subsidiaries of ours in 2005 as a result of our acquisition of additional ownership interests in these two entities.

During 2005, we paid El Paso Corporation (“El Paso”) an additional $7 million in purchase price adjustments related to the merger of GulfTerra Energy Partners, L.P. with a wholly-owned subsidiary of ours, which closed on September 30, 2004 (the “GulfTerra Merger”). The majority of the purchase price adjustments paid to El Paso were related to merger-related financial advisory services and involuntary severance costs. In addition, we made various minor revisions to the GulfTerra Merger purchase price allocation before it was finalized on September 30, 2005.

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Purchase Price Allocation for 2005 Transactions

Our 2005 acquisitions and post-closing purchase price adjustments were accounted for using the purchase method of accounting and, accordingly, the cost of each has been allocated to the assets acquired and liabilities assumed based on their estimated preliminary fair values as follows:

				Indian		Ferrellgas
				Springs	Dixie	Assets	Other (2)	Total
Purchase price allocation:
	Assets acquired in business combination:
		Current assets		$        252	$    (476)	$   6,901	$     2,217	$     8,894
		Property, plant and equipment, net		40,321	90,306	144,092	30,358	305,077
		Investments in and advances to
		unconsolidated affiliates (1)			(36,279)		(10,017)	(46,296)
		Intangible assets		19,095		109	1,009	20,213
		Other assets			31,185		(3,694)	27,491
			Total assets acquired	59,668	84,736	151,102	19,873	315,379
	Liabilities assumed in business combination:
		Current liabilities		(118)	(2,758)	(5,580)	(4,761)	(13,217)
		Long-term debt			(9,982)			(9,982)
		Other long-term liabilities		(61)	(7,697)			(7,758)
		Minority interest			(4,586)		11,603	7,017
			Total liabilities assumed	(179)	(25,023)	(5,580)	6,842	(23,940)
			Total assets acquired less liabilities assumed	59,489	59,713	145,522	26,715	291,439
			Total consideration given	74,854	68,608	145,522	37,618	326,602
	Goodwill			$   15,365	$   8,895	$          -	$   10,903	$   35,163
(1)    Represents carrying value of our investment prior to consolidation. (2)    Includes purchase accounting adjustments for the GulfTerra Merger and preliminary purchase price allocations for the Mid-America, Seminole, Belle Rose and petrochemical pipeline transactions.

The purchase price allocations for our 2005 transactions are preliminary. We engaged an independent third-party business valuation expert to assess the fair value of tangible and intangible assets acquired in connection with the Indian Springs, Dixie, Belle Rose and Ferrellgas transactions. This information will assist us in developing final purchase price allocations for these transactions. Management developed its own fair value estimates of assets acquired and liabilities assumed in connection with the remaining 2005 transactions. Our preliminary values are subject to final valuation reports and additional information.

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10. Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets at December 31, 2005:

		Gross	Accum.	Carrying
		Value	Amort.	Value
NGL Pipelines & Services:
	Shell Processing Agreement	$      206,216	$     (56,157)	$   150,059
	Natural gas processing and NGL business
	customer relationships (1)	49,784	(7,829)	41,955
	Markham NGL storage contracts (1)	32,664	(5,444)	27,220
	Toca-Western contracts	31,229	(5,595)	25,634
	Indian Springs customer relationships	16,439	(1,954)	14,485
	Mont Belvieu storage contracts	8,127	(929)	7,198
	Other	10,804	(1,577)	9,227
	Segment total	355,263	(79,485)	275,778
Onshore Natural Gas Pipelines & Services:
	San Juan Gathering System customer relationships (1)	331,311	(30,065)	301,246
	Petal & Hattiesburg natural gas storage contracts (1)	100,499	(10,742)	89,757
	Texas Intrastate pipeline customer relationships (1)	20,992	(2,538)	18,454
	Other	4,996	(610)	4,386
	Segment total	457,798	(43,955)	413,843
Offshore Pipelines & Services:
	Offshore pipeline & platform customer relationships (1)	205,845	(32,480)	173,365
	Other	1,167		1,167
	Segment total	207,012	(32,480)	174,532
Petrochemical Services:
	Mont Belvieu propylene fractionation contracts	53,000	(5,931)	47,069
	Other	3,674	(1,270)	2,404
	Segment total	56,674	(7,201)	49,473
	Total all segments	$   1,076,747	$   (163,121)	$   913,626
(1)   Acquired in connection with the GulfTerra Merger.

Our significant intangible assets can be classified into the following categories: (i) the Shell Processing Agreement, (ii) the intangible assets we acquired in connection with the GulfTerra Merger, and (iii) other customer relationships and contracts. The following is a description of these significant categories:

Shell Processing Agreement. The Shell Processing Agreement grants us the right to process Shell’s (or its assignee’s) current and future production within the state and federal waters of the Gulf of Mexico. We acquired this intangible asset in connection with our 1999 acquisition of certain of Shell’s midstream energy assets located along the Gulf Coast. The value of the Shell Processing Agreement is being amortized on a straight-line basis over the remainder of its initial 20-year contract term through 2019.

Intangible assets acquired in connection with GulfTerra Merger. We acquired customer relationship and contract-based intangible assets in connection with the GulfTerra Merger. The customer relationship intangible assets represent the exploration and production, natural gas processing and NGL fractionation customer bases served by certain assets acquired in the GulfTerra merger. The contract-based intangible assets represent the rights we acquired in connection with the GulfTerra Merger, which stem from discrete contracts to provide storage services for natural gas and NGLs.

The value we assigned to these customer relationships is being amortized to earnings using methods that closely resemble the pattern in which the economic benefits of the underlying oil and natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. Our estimate of the useful life of each resource base is based on a number of factors, including third-party

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reserve estimates, the economic viability of production and exploration activities and other industry factors. This group of intangible assets primarily consists of the (i) Offshore Pipelines & Platforms customer relationships; (ii) San Juan Gathering System customer relationships; (iii) Texas Intrastate pipeline customer relationships; and (v) Natural gas processing and NGL business customer relationships.

The contract-based intangible assets are being amortized over the estimated useful life (or term) of each agreement, which we estimate to range from two to eighteen years. This group of intangible assets consists of the (i) Petal and Hattiesburg natural gas storage contracts and (ii) Markham NGL storage contracts.

Other significant customer relationship and contract-based intangible assets. In January 2005, we acquired customer relationship intangible assets in connection with our purchase of indirect ownership interests in the Indian Springs natural gas gathering pipelines and processing assets. We are amortizing these intangible assets over a 19-year period, which is the expected life of the customers’ underlying resource bases.

In 2002, we acquired contract-based intangible assets in connection with the purchase of (i) a propylene fractionation facility and underground NGL and petrochemical storage caverns located in Mont Belvieu, Texas and (ii) a natural gas processing and NGL fractionation facility located in Louisiana (the “Toca-Western” contracts). In general, the values assigned to these intangible assets are being amortized on a straight-line basis over the estimated remaining economic life of underlying assets to which they relate, which ranged from 20 to 35 years at inception.

Goodwill

Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized; however, it is subject to annual impairment testing. The following table summarizes our goodwill amounts by segment at December 31, 2005:

NGL Pipelines & Services
	GulfTerra Merger		$       23,927
	Acquisition of Indian Springs natural gas processing assets		13,180
	Other		17,853
Onshore Natural Gas Pipelines & Services
	GulfTerra Merger		280,812
	Acquisition of Indian Springs natural gas gathering assets		2,185
Offshore Pipelines & Services
	GulfTerra Merger		82,386
Petrochemical Services
	Acquisition of Mont Belvieu propylene fractionation assets		73,690
		Totals	$     494,033

The goodwill resulting from the GulfTerra Merger can be attributed to our belief (at the time the merger was consummated) that the combined partnerships would benefit from the strategic location of each partnership’s assets and the industry relationships that each possessed. In addition, we expected that various operating synergies would develop (such as reduced general and administrative costs and interest savings) that could improve financial results of the merged entities. Based on miles of pipelines, GulfTerra was one of the largest natural gas gathering and transportation companies serving producers in 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.

The remainder of our goodwill amounts are associated with prior acquisitions, principally that of our purchase of propylene fractionation assets in February 2002. We also recorded goodwill in connection

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with our acquisition of indirect ownership interests in the Indian Springs natural gas gathering and processing assets in January 2005.

11. Debt Obligations

Our consolidated debt consisted of the following at December 31, 2005:

Operating Partnership debt obligations:
	Multi-Year Revolving Credit Facility, variable rate, due October 2010		$        490,000
	Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54,000
	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
	Senior Notes I, 5.00% fixed-rate, due March 2015 (1)		250,000
	Senior Notes J, 5.75% fixed-rate, due March 2035 (2)		250,000
	Senior Notes K, 4.950% fixed-rate, due June 2010 (3)		500,000
Dixie Revolving Credit Facility, variable rate, due June 2007			17,000
Debt obligations assumed from GulfTerra			5,068
		Total principal amount	4,866,068
Other, including unamortized discounts and premiums and changes in fair value (4)			(32,287)
		Long-term debt	$     4,833,781
Standby letters of credit outstanding			$         33,129
(1)    Senior Notes I were issued at 99.379% of their face amount in February 2005. (2)    Senior Notes J were issued at 98.691% of their face amount in February 2005. (3)    Senior Notes K were issued at 99.834% of their face amount in June 2005. (4)    This amount includes $18.2 million related to fair value hedges and $14.1 million in net unamortized discounts.

Letters of credit

At December 31, 2005, we had $33.1 million in standby letters of credit outstanding, which were issued under our Multi-Year Revolving Credit Facility.

Enterprise Products Partners-Subsidiary guarantor relationships

At December 31, 2005, through grantor agreements that are non-recourse to Enterprise Products GP, Enterprise Products Partners acts as guarantor of the debt obligations of the Operating Partnership, with the exception of the Dixie revolving credit facility and the senior subordinated notes of GulfTerra. If the Operating Partnership were to default on any debt Enterprise Products Partners guarantees, Enterprise Products Partners would be responsible for full repayment of that obligation.

The Operating Partnership’s senior indebtedness is structurally subordinated to and ranks junior in right of payment to the indebtedness of GulfTerra and Dixie. This subordination feature exists only to the extent that the repayment of debt incurred by GulfTerra and Dixie is dependent upon the assets and operations of these two entities. The Dixie revolving credit facility is an unsecured obligation of Dixie (of which we own 65.9% of its capital stock). The senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).

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Operating Partnership debt obligations

Multi-Year Revolving Credit Facility. In August 2004, the Operating Partnership entered into a five-year multi-year revolving credit agreement in connection with the completion of the GulfTerra Merger. In October 2005, the borrowing capacity under this credit agreement was increased from $750 million to $1.25 billion, with the possibility that the borrowing capacity could be further increased to $1.4 billion (subject to certain conditions). In addition, the maturity date for debt outstanding under the facility was extended from September 2009 to October 2010. The Operating Partnership may make up to two requests for one-year extensions of the maturity date (subject to certain conditions). There is no limit on the amount of standby letters of credit that can be outstanding under the amended facility.

The Operating Partnership’s borrowings under this agreement are unsecured general obligations that are non-recourse to Enterprise Products GP. Enterprise Products Partners 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 related to Enterprise Products Partners’ ability to incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; and make certain investments. The loan agreement also requires Enterprise Products Partners to satisfy certain financial covenants at the end of each fiscal quarter. The Multi-Year Revolving Credit Facility restricts the Operating Partnership’s ability to pay cash distributions to us if a default or an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid.

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 Enterprise Products Partners 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.

The indenture agreement for this loan contains an acceleration clause whereby if the Operating Partnership’s credit rating by Moody's declines below Baa3 in combination with our credit rating at Standard & Poor's remaining at BB+ or lower, 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, Enterprise Products Partners would have to either redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to support its obligation under this loan.

Senior Notes B through K. These fixed-rate notes are unsecured obligations 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 Enterprise Products GP. Enterprise Products Partners has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. Enterprise Products Partners’ guarantee of such notes is non-recourse to Enterprise Products GP.

Senior Notes B through D are subject to make-whole redemption rights and were issued under an indenture containing certain covenants. These covenants restrict Enterprise Products Partners’ ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. The remainder of the Senior Notes (E through K) are also subject to similar covenants.

Senior Notes E, F, G, and H were issued as private placement debt in September 2004 and generated an aggregate $2 billion in proceeds, which were used to repay amounts borrowed under the then

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existing 364-Day Acquisition Credit Facility. Senior Notes E through H were exchanged for registered debt securities in March 2005.

Senior Notes I and J were issued as private placement debt in February 2005 and generated an aggregate $500 million in proceeds, which were used to repay $350 million due under the then existing Senior Notes A (which matured in March 2005) and the remainder for general partnership purposes, including the temporary repayment of amounts then outstanding under the Multi-Year Revolving Credit Facility. Senior Notes I and J were exchanged for registered debt securities in August 2005.

Senior Notes K were issued as registered securities in June 2005 and generated $500 million in proceeds, which were used for general partnership purposes, including the temporary repayment of amounts then outstanding under the Multi-Year Revolving Credit Facility. Senior Notes K were issued under a $4 billion universal shelf registration statement filed by Enterprise Products Partners in March 2005.

Dixie Revolving Credit Facility

As a result of acquiring a controlling interest in Dixie in February 2005, we began consolidating the financial statements of Dixie with those of our own. Dixie’s debt obligations consist of a senior unsecured revolving credit facility having a borrowing capacity of $28 million.

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 either (i) a Eurodollar rate plus an applicable margin or (ii) the greater of (a) the Prime Rate or (b) the Federal Funds Rate by ½%.

This revolving credit agreement contains various covenants related to Dixie’s ability to incur certain indebtedness; grant certain liens; enter into merger transactions; and make certain investments. The loan agreement also requires Dixie to satisfy a minimum net worth financial covenant. The revolving credit agreement restricts Dixie’s ability to pay cash dividends to us and its other stockholders if a default or an event of default (as defined in the credit agreement) has occurred and its continuing at the time such dividend is scheduled to be paid.

Debt Obligations assumed from GulfTerra

Senior and Senior Subordinated Notes. Upon completion of the GulfTerra Merger, we recorded in consolidation $921.5 million of GulfTerra Energy Partners, L.P.’s then outstanding senior and senior subordinated notes. Of this amount, $915 million was purchased by our Operating Partnership in October 2004 pursuant to its tender offers for such debt. The Operating Partnership financed these purchases using borrowings under its 364-Day Acquisition Credit Facility. The noteholders also approved (as a condition to accepting the tender offers) amendments that removed all restrictive covenants governing the GulfTerra notes.

The $5.1 million in principal remaining outstanding at December 31, 2005 bears fixed-rate interest of 8.5% and matures in June 2010.

Covenants

We are in compliance with the covenants of our consolidated debt agreements at December 31, 2005.

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Information regarding variable interest rates paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our significant consolidated variable-rate debt obligations during 2005.

	Range of	Weighted-average
	interest rates	interest rate
	paid	paid
Multi-Year Revolving Credit Facility	3.22% to 7.00%	4.25%
Dixie Revolving Credit Facility	3.66% to 4.67%	4.12%

Consolidated debt maturity table

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

2006	None.
2007	$       517,000
2008	None.
2009	500,000
2010	1,049,068
Thereafter	2,800,000
Total scheduled principal payments	$    4,866,068

Joint venture debt obligations

We have three unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at December 31, 2005, (ii) total debt of each unconsolidated affiliate at December 31, 2005, on a 100% basis to the joint venture, and (iii) the corresponding scheduled maturities of such debt.

	Our		Scheduled Maturities of Debt
	Ownership							After
	Interest	Total	2006	2007	2008	2009	2010	2010
Cameron Highway	50.0%	$ 415,000			$  25,000	$ 25,000	$ 50,000	$ 315,000
Poseidon	36.0%	95,000			95,000
Evangeline	49.5%	30,650	$ 5,000	$ 5,000	5,000	5,000	10,650
Total		$ 540,650	$ 5,000	$ 5,000	$ 125,000	$ 30,000	$ 60,650	$ 315,000

The credit agreements of our joint ventures contain various affirmative and negative covenants, including financial covenants. Our joint ventures were in compliance with all such covenants at December 31, 2005. The credit agreements of our joint ventures restrict their ability to pay cash dividends if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend is scheduled to be paid.

In March 2005, we contributed $72 million to Deepwater Gateway to assist in the repayment of its $144 million term loan. Our joint venture partner in Deepwater Gateway also contributed $72 million. Deepwater Gateway used funds borrowed under its term loan to fund a substantial portion of the cost to construct the Marco Polo platform and related facilities.

The following information summarizes significant terms of the debt obligations of our unconsolidated affiliates at December 31, 2005:

Cameron Highway. In July 2003, Cameron Highway entered into a $325 million project loan facility to finance a substantial portion of the cost to construct its crude oil pipeline. In June 2005, Cameron Highway executed a new term loan agreement with a total credit commitment of $415 million and borrowed the full amount, which was used to repay principal amounts outstanding under the project

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loan facility and to make $95 million in cash distributions to its partners. We received a partial return of our investment in Cameron Highway of $47.5 million in connection with this special distribution. In connection with this refinancing, Cameron Highway incurred $22 million in one-time cash make-whole premiums and related fees and non-cash charges.

In December 2005, Cameron Highway issued $415 million of private placement, non-recourse senior secured notes due December 2017. Proceeds from the issuance of these senior secured notes were used to repay the $415 million term loan that Cameron Highway entered into during June 2005. The senior secured notes were issued in two series - $365 million of Series A notes, which have a fixed-rate interest of 5.86%, and $50 million of Series B notes, which have a variable-rate interest based on a Eurodollar rate plus 1%. At December 31, 2005, the variable interest rate charged under the Series B notes was 4.52%.

The notes are secured by (i) mortgages on and pledges of substantially all of the assets of Cameron Highway, (ii) mortgages on and pledges of certain assets related to certain rights of way and pipeline assets of an indirect wholly-owned subsidiary of ours that serves as the operator of the Cameron Highway Oil Pipeline, (iii) pledges by us and our joint venture partner in Cameron Highway of our 50% partnership interests in Cameron Highway, and (iv) letters of credit in an initial amount of $18.4 million each issued by our Operating Partnership and an affiliate of our joint venture partner. Except for the foregoing, the noteholders do not have any recourse against our assets or any of our subsidiaries under the note purchase agreement.

Poseidon. Poseidon has entered into a $170 million revolving credit facility that matures in January 2008. The interest rates charged under this revolving credit facility are variable and depend on the ratio of Poseidon’s total debt to its earnings before interest, taxes, depreciation and amortization. This credit agreement is secured by substantially all of Poseidon’s assets. The variable interest rate charged on this debt at December 31, 2005 was 5.34%.

Evangeline. At December 31, 2005, long-term debt for Evangeline consisted of (i) $23.2 million in principal amount of 9.9% fixed-rate Series B senior secured notes due 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 reserve 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 as a result of its acquisition of a contract-based intangible asset in the 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. Variable rate interest accrues on the subordinated note at a Eurodollar rate plus ½%. The variable interest rate charged on this note at December 31, 2005 was 3.58%.

12. Minority Interest

Minority interest represents third-party and related party ownership interests in the net assets of certain of our subsidiaries. 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. The following table shows the components of minority interest at December 31, 2005:

Limited partners of Enterprise Products Partners:
	Non-affiliates of Enterprise Products GP	$    4,403,490
	Affiliates of Enterprise Products GP	740,130
Joint venture partners		103,169
		$    5,246,789

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The minority interest attributable to the limited partners of Enterprise Products Partners consists of common units held by the public and our affiliates (primarily EPCO), and is net of unamortized deferred compensation of $14.6 million at December 31, 2005, which represents the value of restricted common units of Enterprise Products Partners issued to key employees of EPCO. The minority interest attributable to joint venture partners as of December 31, 2005, is primarily attributable to our partners in Tri-States, Seminole, Wilprise, Independence Hub, Dixie and Belle Rose.

13. Members’ Equity

Earnings and cash distributions are allocated to Member capital accounts in accordance with their respective membership percentages. On September 30, 2004, El Paso was granted a 9.9% membership interest in Enterprise Products GP in connection with our acquisition of El Paso’s 50% membership interest in the general partner of GulfTerra Energy Partners, L.P. In January 2005, an affiliate of EPCO purchased El Paso’s 9.9% membership interest in Enterprise Products GP. As a result of these transactions and prior to August 2005, affiliates of EPCO (other than Enterprise GP Holdings – see below) owned 100% of the membership interests in Enterprise Products GP. El Paso no longer owns any interest in Enterprise Products GP.

In August 2005, Duncan Family Interests, Inc., Dan Duncan, LLC and DFI GP Holdings L.P. contributed their 85.6%, 4.5% and 9.9% membership interests, respectively, in Enterprise Products GP to Enterprise GP Holdings. As a result of this contribution, Enterprise GP Holdings owns 100% of the membership interests in Enterprise Products GP. Enterprise GP Holdings is a publicly traded limited partnership that completed an initial public offering of its common units in August 2005 and trades on the NYSE under symbol “EPE.”

Enterprise GP Holdings made a cash capital contribution to us of $364.5 million in August 2005 using proceeds from borrowings under its credit facility. We used the proceeds from this contribution to fully repay the principal and interest outstanding under a note payable to an affiliate.

Accumulated other comprehensive income

The following table summarizes the effect of our cash flow hedging financial instruments (see Note 5) on accumulated other comprehensive income (“AOCI”) since December 31, 2004.

		Interest Rate Fin. Instrs.		Accumulated
			Forward-	Other
	Commodity		Starting	Comprehensive
	Financial	Treasury	Interest	Income
	Instruments	Locks	Rate Swaps	Balance
Balance, December 31, 2004	$    1,434	$    4,572	$    18,548	$     24,554
Change in fair value of commodity financial instruments	(1,434)			(1,434)
Reclassification of gain on settlement of interest rate financial instruments		(445)	(3,603)	(4,048)
Balance, December 31, 2005	$           -	$    4,127	$    14,945	$     19,072

During the first quarter of 2005, we reclassified into income a $1.4 million gain related to a commodity cash flow hedge we acquired in connection with the GulfTerra Merger. This gain resulted from an increase in fair value of the underlying financial instrument from the value recorded for the commodity cash flow hedge at September 30, 2004. In 2006, we expect to reclassify $4.3 million of accumulated other comprehensive income that was generated by treasury lock and forward-starting interest rate swap transactions to reduce interest expense. For additional information regarding our use of financial instruments, see Note 5.

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14. Business Segments

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.

We have four reportable business segments: NGL Pipelines & Services, Onshore Natural Gas Pipelines & Services, Offshore Pipelines & Services and Petrochemical Services. Our business segments are generally organized and managed according to the type of services rendered (or technology employed) and products produced and/or sold.

Our NGL Pipelines & Services business segment includes our (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,810 miles and related storage facilities including our Mid-America Pipeline System, Seminole Pipeline and Dixie Pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes our import and export terminal operations.

Our Onshore Natural Gas Pipelines & Services business segment includes 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, we own two salt dome natural gas storage facilities located in Mississippi and lease natural gas storage facilities located in Texas and Louisiana.

Our Offshore Pipelines & Services business segment includes (i) approximately 1,190 miles of offshore natural gas pipelines strategically located to serve production areas including some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 870 miles of offshore Gulf of Mexico 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.

Our Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex, and an octane additive production facility. This segment also includes approximately 690 miles of petrochemical pipeline systems.

Our integrated midstream energy asset system (including the midstream energy assets of our equity method investees) provides services to producers and consumers of natural gas, NGLs and petrochemicals. Our asset system has multiple entry points. In general, hydrocarbons can enter our asset system through a number of ways, including an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an NGL gathering pipeline, an NGL fractionator, an NGL storage facility, an NGL transportation or distribution pipeline or an onshore natural gas pipeline.

Currently, our plant-based operations are located primarily in Texas, Louisiana, Mississippi and New Mexico. Our natural gas, NGL and crude oil pipelines 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 and serve customers in a number of regions of 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 the total value of segment assets is construction-in-progress. Segment assets represent the net carrying value of facilities and projects that contribute to the gross operating margin of a particular segment. Since assets under construction generally do not contribute to segment gross operating margin, such assets are excluded from the segment asset 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.

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

			Operating Segments
				Onshore
			Offshore	Natural Gas	NGL		Adjustments
			Pipelines	Pipelines	Pipelines	Petrochemical	and	Consolidated
			& Services	& Services	& Services	Services	Eliminations	Totals
Segment assets:
		At December 31, 2005	$  632,222	$  3,622,318	$  3,075,048	$  504,841	$  854,595	$  8,689,024
Investments in and advances to
	unconsolidated affiliates (see Note 8):
		At December 31, 2005	316,844	4,644	130,376	20,057		471,921
Intangible Assets (see Note 10):
		At December 31, 2005	174,532	413,843	275,778	49,473		913,626
Goodwill (see Note 10):
		At December 31, 2005	82,386	282,997	54,960	73,690		494,033

15. Related Party Transactions

Relationship with EPCO and affiliates

General. We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities:

• EPCO and its private company subsidiaries;

• Enterprise GP Holdings, which owns 100% of the membership interest in and controls Enterprise Products GP;

• EPE Unit L.P. (the “Employee Partnership”); and

• TEPPCO Partners L.P. (“TEPPCO”) and its general partner (“TEPPCO GP”), which are controlled by affiliates of EPCO.

Unless noted otherwise, our agreements with EPCO are not the result of arm’s length transactions. As a result, we cannot provide assurance that the terms and provisions of such agreements are at least as favorable to us as we could have obtained from unaffiliated third parties.

Enterprise Products Partners was formed in 1998 to own and operate certain NGL assets contributed to it by EPCO. EPCO is a private company controlled by Dan L. Duncan, who is also a director and Chairman of Enterprise Products GP. 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.

At December 31, 2005, EPCO and its affiliates beneficially owned 100% of the membership interests in Enterprise Products GP and 144,055,494 (or 36.2%) of the outstanding Enterprise Products Partners’ common units. In January 2005, an affiliate of EPCO acquired 13,454,498 of Enterprise Products Partners’ common units and a 9.9% membership interest in Enterprise Products GP from El Paso for approximately $425 million in cash. As a result of this transaction and until August 2005, EPCO and certain of its affiliates owned 100% of the membership interests of Enterprise Products GP and El Paso no longer owned any of the membership interests in Enterprise Products GP.

In August 2005, affiliates of EPCO contributed their 100% membership interests in Enterprise Products GP and the 13,454,498 Enterprise Products Partners’ common units they acquired from El Paso to Enterprise GP Holdings, another affiliate of EPCO. As a result of this contribution, Enterprise GP Holdings owns 100% of the membership interests of Enterprise Products GP and an approximate 3.4% limited partner interest in Enterprise Products Partners. Enterprise GP Holdings is a publicly traded limited partnership that completed an initial public offering of its common units in August 2005, and its only cash

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generating assets consist of its membership interests in Enterprise Products GP and its limited partner interest in Enterprise Products Partners. At December 31, 2005, EPCO and its affiliates owned 86.5% of Enterprise GP Holdings, including 100% of EPE Holdings, LLC (“EPE Holdings”), the general partner of Enterprise GP Holdings.

We are a separate legal entity from EPCO and its other affiliates, with assets and liabilities that are separate from those of EPCO and its other affiliates. EPCO depends on the cash distributions it receives from us, Enterprise GP Holdings and other investments to fund its other operations and to meet its debt obligations. EPCO and its affiliates received $243.9 million in cash distributions from us during 2005 in connection with its membership interests in Enterprise Products GP and its limited partner interest in Enterprise Products Partners.

The ownership interests in us that are owned or controlled by EPCO and its affiliates, other than Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of an EPCO affiliate. EPCO’s credit facility contains customary and other events of default relating to EPCO and certain affiliates, including Enterprise GP Holdings, us and TEPPCO. In the event of a default under such credit facility, a change in control of us could occur.

Our executive and other officers are employees of EPCO, including Robert G. Phillips who is President, Chief Executive Officer and a Director of Enterprise Products GP. In addition, we have entered into an agreement with an affiliate of EPCO to provide trucking services to us for the transportation of NGLs and other products. In addition, we buy from and sell certain NGL products to another affiliate of EPCO at market-related prices in the normal course of business. We also lease office space in various buildings from affiliates of EPCO related to our corporate headquarters in Houston, Texas at rates that approximate market rates.

Relationship with TEPPCO. In February 2005, an affiliate of EPCO acquired 100% of the membership interests of TEPPCO GP and 2,500,000 common units of TEPPCO for approximately $1.2 billion in cash. TEPPCO GP owns a 2% general partner interest in TEPPCO and is the managing partner of TEPPCO and its subsidiaries. In June 2005, the employees of TEPPCO became EPCO employees.

In March 2005, the Bureau of Competition of the FTC delivered written notice to EPCO’s legal advisor that it was conducting a non-public investigation to determine whether EPCO’s acquisition of TEPPCO GP may tend substantially to lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with EPCO’s purchase of TEPPCO GP. EPCO and its affiliates, including us, may receive similar inquiries from other regulatory authorities and we intend to cooperate fully with any such investigations and inquiries. In response to such FTC investigation or any inquiries EPCO and its affiliates may receive from other regulatory authorities, we may be required to divest certain assets.

In February 2006, we and TEPPCO entered into a letter of intent related to the formation of a joint venture to expand TEPPCO’s Jonah Gas Gathering System (“the Jonah system”) located in the Green River Basin in southwestern Wyoming. The proposed expansion of the Jonah system would increase the natural gas gathering and transportation capacity of the Jonah system from 1.5 Bcf/d to 2.0 Bcf/d. The letter of intent stipulates that we will be responsible for all activities related to the construction of the expansion of the Jonah system, including advancing of all expenditures necessary to plan, engineer and construct the expansion project. We estimate that total funds needed for this project will approximate $200 million and that the expansion assets will be placed in service in late 2006. The amounts we advance to complete the expansion of the Jonah system will constitute a subscription for an equity interest in the proposed joint venture. TEPPCO has the option to return to us up to 100% of the amounts we advance (i.e., the subscription amounts). If TEPPCO returns any portion of the subscription to us, the relative interests of us and TEPPCO in the new joint venture would be adjusted accordingly. The proposed joint venture arrangement will terminate without liability to either party if TEPPCO returns 100% of the advances we make in connection with the expansion project, including carrying costs and expenses.

In January 2006, we announced our intent to purchase from TEPPCO the Pioneer natural gas processing plant located in Opal, Wyoming and the rights to process natural gas originating from the Jonah

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and Pinedale fields in the Greater Green River Basin in Wyoming. Upon execution of definitive agreements, the receipt of all necessary regulatory approval and approvals from the boards of directors of TEPPCO and Enterprise Products GP, we would purchase the Pioneer plant for $36 million and commence construction to increase its processing capacity from 275 MMcf/d to 550 MMcf/d. We expect this expansion to be completed in mid-2006.

Employee Partnership. In connection with the initial public offering of Enterprise GP Holdings, EPCO formed the Employee Partnership. EPCO serves as the general partner of the Employee Partnership. In connection with the closing of Enterprise GP Holdings’ initial public offering, EPCO Holdings, Inc., a wholly owned subsidiary of EPCO, borrowed $51 million under its credit facility and contributed the borrowings to its wholly-owned subsidiary, Duncan Family Interests, Inc. (“Duncan Family Interests”), which, in turn, contributed $51 million to the Employee Partnership as a capital contribution with respect to its Class A limited partner interest. The Employee Partnership used the contributed funds to purchase 1,821,428 units directly from Enterprise GP Holdings at the initial public offering price. Certain EPCO employees, including all of Enterprise Products GP’s executive officers other than the Chairman, have been issued Class B limited partner interests without any capital contribution and admitted as Class B limited partners of the Employee Partnership.

Unless otherwise agreed to by EPCO, Duncan Family Interests and a majority in interest of the Class B limited partners of the employee partnership, the employee partnership will terminate at the earlier of five years following the closing of Enterprise GP Holdings’ initial public offering or a change in control of Enterprise GP Holdings or its general partner. The Employee Partnership has the following material terms with respect to distributions:

• Distributions of Cashflow—each quarter, 100% of the distributions from units held by the Employee Partnership will be distributed to Duncan Family Interests until it has received the Class A preferred return (as defined below), and any remaining distributions from the Employee Partnership will be distributed to the Class B limited partners. The Class A preferred return will equal 1.5625% per quarter, or 6.25% per annum, of Duncan Family Interest’s capital base. Duncan Family Interest’s capital base will equal $51 million, increased by any unpaid Class A preferred return from prior periods, and decreased by any distributions of sale proceeds to Duncan Family Interests as described below.

• Liquidating Distributions—Upon liquidation of the Employee Partnership, units having a fair market value equal to Duncan Family Interest’s capital base will be distributed to Duncan Family Interests, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partners.

• Sale Proceeds—If the Employee Partnership sells any units, the sale proceeds will be distributed to Duncan Family Interests and the Class B limited partners in the same manner as liquidating distributions described above.

The Class B limited partner interests in the Employee Partnership that are owned by EPCO employees are subject to forfeiture if the participating employee’s employment with EPCO and its affiliates is terminated prior to the fifth anniversary of the closing of Enterprise GP Holdings’ initial public offering, with customary exceptions for death, disability and certain retirements. The risk of forfeiture associated with the Class B limited partner interests in the Employee Partnership will also lapse upon certain change of control events.

We will not reimburse EPCO, the Employee Partnership or any of their affiliates or partners, through the administrative services agreement or otherwise, for any expenses related to the Employee Partnership or the contribution of $51 million to the Employee Partnership or the purchase of the units by the Employee Partnership.

Administrative Services Agreement. We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative

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services agreement (“ASA”). We, Enterprise GP Holdings and its general partner, and TEPPCO and its general partner are parties to the ASA. The significant terms of the ASA are as follows:

• EPCO will provide selling, general, administrative, management, engineering and operating services as may be necessary to manage and operate our business, properties and assets (in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services.

• We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided to us by EPCO.

• EPCO has allowed us to participate as named insureds in its overall insurance program with the associated costs being charged to us.

Under the ASA, EPCO subleases to us (for $1 per year) certain equipment which it holds pursuant to operating leases and has assigned to us its purchase option under such leases (the “retained leases”). EPCO remains liable for the actual cash lease payments associated with these agreements. At December 31, 2005, the retained leases were for a cogeneration unit and approximately 100 railcars. Should we decide to exercise the purchase options associated with the retained leases, $2.3 million would be payable in 2008 and $3.1 million in 2016.

We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Likewise, we reimburse EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to ASA based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs).

The ASA addresses potential conflicts that may arise among Enterprise Products Partners, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings and the EPCO Group, which includes EPCO and its affiliates (excluding Enterprise Products GP, Enterprise Products Partners and its subsidiaries, Enterprise GP Holdings and EPE Holdings and TEPPCO, TEPPCO GP and their controlled affiliates). The ASA provides, among other things, that:

• if a business opportunity to acquire equity securities is presented to the EPCO Group, Enterprise Products GP, Enterprise Products Partners, EPE Holdings or Enterprise GP Holdings, then Enterprise GP Holdings will have the first right to pursue such opportunity. “Equity securities” are defined to include:

• general partner interests (or securities which have characteristics similar to general partner interests) and incentive distribution rights or similar rights in publicly traded partnerships or interests in “persons” that own or control such general partner or similar interests (collectively, “GP Interests”) and securities convertible, exercisable, exchangeable or otherwise representing ownership or control of such GP Interests; and

• incentive distribution rights and limited partner interests (or securities which have characteristics similar to incentive distribution rights or limited partner interests) in publicly traded partnerships or interests in “persons” that own or control such limited partner or similar interests (collectively, “non-GP Interests”); provided that such non-GP Interests are associated with GP Interests and are owned by the owners of GP Interests or their respective affiliates.

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Enterprise GP Holdings will be presumed to desire to acquire the equity securities until such time as EPE Holdings advises the EPCO Group and Enterprise Products GP that Enterprise GP Holdings has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to exceed $100 million, the decision to decline the acquisition will be made by the Chief Executive Officer of EPE Holdings after consultation with and subject to the approval of the Audit and Conflicts Committee of EPE Holdings. If the purchase price is reasonably likely to be less than such threshold amount, the Chief Executive Officer of EPE Holdings may make the determination to decline the acquisition without consulting the Audit and Conflicts Committee of EPE Holdings. In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group and Enterprise Products GP, Enterprise Products Partners will have the second right to the pursue such acquisition. Enterprise Products Partners will be presumed to desire to acquire the equity securities until such time as Enterprise Products GP advises the EPCO Group that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing Enterprise Products GP’s Chief Executive Officer and Audit and Conflicts Committee. In the event that Enterprise Products Partners abandons the acquisition and so notifies the EPCO Group, the EPCO Group may pursue the acquisition without any further obligation to any other party or offer such opportunity to other affiliates.

• if any business opportunity not covered by the preceding bullet point is presented to the EPCO Group, Enterprise Products GP, Enterprise Products Partners, EPE Holdings or Enterprise GP Holdings, Enterprise Products Partners will have the first right to pursue such opportunity. Enterprise Products Partners will be presumed to desire to pursue the business opportunity until such time as Enterprise Products GP advises the EPCO Group and EPE Holdings that Enterprise Products Partners has abandoned the pursuit of such business opportunity. In the event that the purchase price or cost associated with the business opportunity is reasonably likely to exceed $100 million, the decision to decline the business opportunity will be made by the Chief Executive Officer of Enterprise Products GP after consultation with and subject to the approval of the Audit and Conflicts Committee of Enterprise Products GP. If the purchase price or cost is reasonably likely to be less than such threshold amount, the Chief Executive Officer of Enterprise Products GP may make the determination to decline the business opportunity without consulting Enterprise Products GP’s Audit and Conflicts Committee. In the event that Enterprise Products Partners abandons the business opportunity and so notifies the EPCO Group and EPE Holdings, Enterprise GP Holdings will have the second right to the pursue such business opportunity. Enterprise GP Holdings will be presumed to desire to pursue such business opportunity until such time as EPE Holdings advises the EPCO Group that Enterprise GP Holdings has abandoned the pursuit of such business opportunity. In determining whether or not to pursue the business opportunity, Enterprise GP Holdings will follow the same procedures applicable to Enterprise Products Partners, as described above but utilizing EPE Holdings’ Chief Executive Officer and Audit and Conflicts Committee. In the event that Enterprise GP Holdings abandons the business opportunity and so notifies the EPCO Group, the EPCO Group may pursue the business opportunity without any further obligation to any other party or offer such opportunity to other affiliates.

None of the EPCO Group, Enterprise Products GP, Enterprise Products Partners, EPE Holdings or Enterprise GP Holdings have any obligation to present business opportunities to TEPPCO, TEPPCO GP or their controlled affiliates, and TEPPCO, TEPPCO GP and their controlled affiliates have no obligation to present business opportunities to the EPCO Group, Enterprise Products GP, Enterprise Products Partners, EPE Holdings or Enterprise GP Holdings.

The ASA also outlines an overall corporate governance structure and provides policies and procedures to address potential conflicts of interest among the parties to the ASA, including protection of the confidential information of each party from the other parties and the sharing of EPCO employees between the parties. Specifically, the ASA provides, among other things, that:

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• there shall be no overlap in the independent directors of Enterprise Products GP, EPE Holdings and TEPPCO GP;

• there shall be no sharing of EPCO employees performing commercial and development activities involving certain defined potential overlapping assets between us, Enterprise GP Holdings, and EPCO and its other affiliates (excluding TEPPCO and subsidiaries) on one hand and TEPPCO and its subsidiaries and TEPPCO GP on the other hand; and

• certain screening procedures are to be followed if an EPCO employee performing commercial and development activities becomes privy to commercial information relating to a potential overlapping asset of any entity for which such employee does not perform commercial and development activities.

Relationships with Unconsolidated Affiliates

Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. The following information summarizes significant related party transactions 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. We have furnished $1.2 million in letters of credit on behalf of Evangeline at December 31, 2005.

• We pay Promix for the transportation, storage and fractionation of NGLs. In addition, we sell natural gas to Promix for its plant fuel requirements.

• Additionally, we perform management services for certain of our unconsolidated affiliates.

16. Income Taxes for Certain Pipeline Operations

Our income taxes relate to federal income tax and state franchise and income tax obligations of Seminole and Dixie, which are both corporations and represent our only consolidated subsidiaries subject to such income taxes.

The deferred tax asset shown on our consolidated balance sheet reflects the net tax effects of temporary differences between the subsidiary’s carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The significant components of our deferred tax asset at December 31, 2005 are as follows:

Deferred Tax Assets:
Property, plant and equipment – Dixie	$         855
Net operating loss carryforwards	14,251
Employee benefit plans	2,403
Deferred revenue	448
Accruals	116
Total Deferred Tax Assets	18,073
Deferred Tax Liabilities:
Property, plant and equipment – Seminole	13,907
Other	6
Total Deferred Tax Liabilities	13,913
Net Deferred Tax Assets	$      4,160
Current portion of deferred tax assets	$         554
Long-term portion of deferred tax assets	$      3,606

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17. Commitments and Contingencies

Litigation

On occasion, we are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. Although we are insured against various business risks to the extent we believe 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 our ordinary business activity. We are not aware of any significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.

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 that 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. In connection with our purchase of additional equity interests in the owner of the octane-additive production facility in 2003 from an affiliate of Devon Energy Corporation (“Devon”) and in 2004 from an affiliate of Sunoco, Inc. (“Sun”), Devon and Sun indemnified us for any liability (including liabilities described above) that are in respect of periods prior to the date we purchased such interests. There are no dollar limits or deductibles associated with the indemnities we received from Sun and Devon with respect to potential claims linked to the period of time they held ownership interests in the facility.

Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2005. A description of each type of contractual obligation follows.

				Payment or Settlement due by Period
Contractual Obligations				Total	2006	2007	2008	2009	2010	Thereafter
Scheduled maturities of long-term debt				$ 4,866,068		$ 517,000		$ 500,000	$  1,049,068	$ 2,800,000
Operating lease obligations				$    179,623	$      19,099	$   18,638	$   15,210	$   10,352	$        9,737	$    106,587
Purchase obligations:
	Product purchase commitments:
		Estimated payment obligations:
			Natural gas	$ 1,518,016	$    216,690	$ 216,690	$ 217,283	$ 216,690	$    216,690	$    433,973
			NGLs	$ 6,095,907	$    684,250	$ 619,048	$ 499,900	$ 499,900	$    499,900	$ 3,292,909
			Petrochemicals	$ 1,290,952	$ 1,079,110	$ 159,511	$   52,331
			Other	$      87,162	$      31,578	$   23,176	$   21,548	$   10,712	$          148
		Underlying major volume commitments:
			Natural gas (in BBtus)	127,850	18,250	18,250	18,300	18,250	18,250	36,550
			NGLs (in MBbls)	63,130	9,251	7,741	5,086	5,086	5,086	30,880
			Petrochemicals (in MBbls)	19,717	16,525	2,381	811
	Service payment commitments			$       5,765	$       5,037	$       689	$         39
	Capital expenditure commitments			$    208,575	$    208,575

Scheduled Maturities of Long-Term Debt. We have long and short-term payment obligations under debt agreements such as the indentures governing the Operating Partnership’s senior notes and the credit agreement governing the Operating Partnership’s Multi-Year Revolving Credit Facility. Amounts shown in the table represent our scheduled future maturities of long-term debt principal for the periods indicated. See Note 11 for additional information regarding our consolidated debt obligations.

Operating Lease Obligations. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the preceding table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year for the periods indicated.

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Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, and (iii) land held pursuant to right-of-way agreements. In general, our material lease agreements have original terms that range from 14 to 20 years and include renewal options that could extend the agreements for up to an additional 20 years. Our rental payments under these agreements are generally fixed rates, as specified in the individual contract, which may be subject to escalation provisions for inflation and other market-determined factors. With regards to our underground storage leases, we may also be assessed contingent rental payments when our storage volumes exceed our reserved capacity.

The operating lease commitments shown in the preceding table exclude the non-cash related party expense associated with equipment leases contributed to us by EPCO at our formation (the “retained leases”). EPCO remains liable for the actual cash lease payments associated with these agreements, which it accounts for as operating leases. At December 31, 2005, the retained leases were for a cogeneration unit and approximately 100 railcars. EPCO’s minimum future rental payments under these leases are $2.1 million for each of the years 2006 through 2008, $0.7 million for each of the years 2009 through 2015 and $0.3 million for 2016.

The retained lease agreements contain lessee purchase options, which are at prices that approximate fair value of the underlying leased assets. EPCO has assigned these purchase options to us. Should we decide to exercise the remaining purchase options, up to an additional $2.3 million would be payable in 2008 and $3.1 million in 2016.

Purchase Obligations. We define a purchase obligation as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies 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:

We have long and short-term product purchase obligations for NGLs, petrochemicals and natural gas with third-party suppliers. The prices that we are 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. Our estimated future payment obligations are based on the contractual price under each contract for purchases made at December 31, 2005 applied to all future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. At December 31, 2005, we do not have any product purchase commitments with fixed or minimum pricing provisions having remaining terms in excess of one year.

We have long and short-term commitments to pay third-party 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.

Lastly, 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 the 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. Our capital expenditure commitments also include $95 million for the acquisition of certain pipeline assets during 2006. The preceding table shows these combined amounts for the periods indicated.

Redelivery Commitments

We transport and store 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, 2005, NGL and petrochemical volumes

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aggregating 15.2 million barrels were due to be redelivered to their owners along with 15,512 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 us (see Note 15). This includes the costs associated with equity-based awards granted to these employees. At December 31, 2005, there were 2,082,000 options outstanding to purchase Enterprise Products Partners’ common units that had been granted to employees for which we were responsible for reimbursing EPCO for the costs of such awards.

The weighted-average strike price of the unit option awards granted was $22.16 per common unit. At December 31, 2005, 727,000 of these unit options were exercisable. An additional 25,000, 840,000 and 490,000 of these unit options will be exercisable in 2006, 2008 and 2009, 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.

Performance Guaranty

In December 2004, a subsidiary of the Operating Partnership entered into the Independence Hub Agreement (the “Agreement”) with six oil and natural gas producers. The Agreement, as amended, obligates the subsidiary (i) to construct an offshore platform production facility to process 1 Bcf/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, our Operating Partnership guaranteed the performance of its subsidiary under the Agreement up to $426 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 $341 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 the cost of constructing the platform in the remote scenario where the six producers take over the construction of the platform facility. This performance guarantee continues until the earlier to occur of (i) all of the guaranteed obligations of the subsidiary shall have been terminated, paid or otherwise 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 of the platform will occur in November 2006; therefore, we anticipate that the performance guaranty will exist until at least this future date.

In accordance with FIN 45, “Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” 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 other current liabilities on our Consolidated Balance Sheet at December 31, 2005.

18. Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

We operate predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. As such, our results of operations, cash flows and financial condition may be affected by (i) changes in the commodity prices of these hydrocarbon products and (ii) changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to

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fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.

Our profitability could be impacted by a decline in the volume of natural gas, NGLs and crude oil transported, gathered or processed at our facilities. A material decrease in natural gas or crude oil production or crude oil refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and crude oil handled by our facilities.

A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made with NGL products, (iii) increased competition from petroleum-based products due to the pricing differences, (iv) adverse weather conditions, (v) government regulations affecting commodity prices and production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could also adversely affect our financial position.

Credit Risk due to Industry Concentrations

A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could affect our overall exposure to credit risk since these customers may be affected by similar economic or other conditions. We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults.

Counterparty Risk with respect to Financial Instruments

Where we are exposed to credit risk in our financial instrument transactions, 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.

Weather-Related Risks

We participate as named insureds in EPCO’s current insurance program, which provides us with property damage, business interruption and other coverages, which are customary for the nature and scope of our operations. Historically, most of the insurance carriers in EPCO’s portfolio of coverage were rated “A” or higher by recognized ratings agencies. The financial impact of recent storm events such as Hurricanes Katrina and Rita has resulted in the lowering of credit ratings of many insurance carriers, with a number of providers also being placed on negative credit watch. We are unaware of any of our existing carriers dropping below the “A” rating level. At present, there is no indication of any insurance carrier in the EPCO insurance program being unable or unwilling to meet its coverage obligations.

We believe that EPCO maintains adequate insurance coverage on behalf of us, although insurance will not cover every type of interruption that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available for only reduced amounts of coverage. As a result, EPCO may not be able to renew existing insurance policies on behalf of us or procure other desirable insurance on commercially reasonable terms, if at all. At present, the annualized cost of insurance premiums allocated to us by EPCO for all lines of coverage is approximately $21.1 million. This amount includes a $3.7 million increase in premiums related to Hurricanes Katrina and Rita that we recognized during 2005.

If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated financial position. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that

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interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to pay distributions to partners and, accordingly, adversely affect the market price of Enterprise Products Partners’ common units.

The following is a discussion of the general status of insurance claims related to recent significant storm events that affected our assets. To the extent we include any estimate or range of estimates regarding the dollar value of damages, please be aware that a change in our estimates may occur in the near term as additional information becomes available to us.

Hurricane Ivan insurance claims. Our final purchase price allocation for the GulfTerra Merger includes the expected recovery of $26.2 million, which represents the probable recovery of property damage insurance claims related to completed expenditures for damage to certain assets due to the significant effects of Hurricane Ivan, which struck the eastern U.S. Gulf Coast region in September 2004 prior to the GulfTerra Merger. These expenditures represent our total costs to restore the former GulfTerra damaged facilities to operation. Since this loss event occurred prior to completion of the GulfTerra Merger, the claim was filed under the insurance program of GulfTerra and El Paso. Since year end 2005, we received cash reimbursements from insurance carriers totaling $24.1 million related to these property damage claims, and we expect to recover the remaining $2.1 million by mid-2006. If the final recovery of funds is different than the amount previously expended, we will recognize an income impact at that time.

In addition, we have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan. During the fourth quarter of 2005, we received $4.8 million from such claims. In addition, we estimate an additional $15 million to $16 million will be received during the first quarter of 2006. To the extent we receive cash proceeds from such business interruption claims, they will be recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

Hurricanes Katrina and Rita insurance claims. Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. Inspection and evaluation of damage to our facilities is a continuing effort. We expensed $5 million during 2005 related to property damage insurance deductibles for both storms. To the extent that insurance proceeds from property damage claims do not cover our expenditures (in excess of the insurance deductibles we have expensed), such shortfall will be expensed when realized. We recorded $15.5 million of estimated recoveries from property damage claims based on amounts expended through December 31, 2005. In addition, we expect to file business interruption claims for losses related to these hurricanes. To the extent we receive cash proceeds from such business interruption claims, they will be recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

19. Condensed Financial Information of Operating Partnership

The Operating Partnership conducts substantially all of the business of Enterprise Products Partners. Currently, neither Enterprise Products GP not Enterprise Products Partners have any independent operations and any material assets outside those of the Operating Partnership.

Enterprise Products Partners acts as guarantor of all the Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes, the Dixie revolving credit facility and the amounts remaining outstanding under GulfTerra’s senior subordinated notes. If the Operating Partnership were to default on any debt Enterprise Products Partners guarantees, Enterprise Products Partners would be responsible for full repayment of that obligation. Enterprise Products Partners’ guarantee of these debt obligations is both full and unconditional and non-recourse to Enterprise Products GP. For additional information regarding our consolidated debt obligations, see Note 11.

The reconciling items between our consolidated balance sheet and that of the Operating Partnership are substantially the same as the differences between our consolidated balance sheet and that of Enterprise Products Partners, see Note 1.

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The following table shows condensed consolidated balance sheet data for the Operating Partnership at December 31, 2005:

ASSETS
Current assets		$      1,960,015
Property, plant and equipment, net		8,689,024
Investments in and advances to unconsolidated affiliates		471,921
Intangible assets, net		913,626
Goodwill		494,033
Deferred tax asset		3,606
Other assets		39,014
	Total	$    12,571,239
LIABILITIES AND PARTNERS' EQUITY
Current liabilities		$      1,894,227
Long-term debt		4,833,781
Other long-term liabilities		84,486
Minority interest		106,159
Partners' equity		5,652,586
	Total	$    12,571,239
Total Operating Partnership debt obligations guaranteed
by Enterprise Products Partners		$      4,844,000

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