EXHIBIT 99.1

Enterprise Products GP, LLC

Consolidated Balance Sheet at December 31, 2007

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 at December 31, 2007		3

Notes to Consolidated Balance Sheet
	Note 1 – Company Organization	4
	Note 2 – General Accounting Policies and Related Matters	5
	Note 3 – Recent Accounting Developments	11
	Note 4 – Accounting for Unit-Based Awards	12
	Note 5 – Employee Benefit Plans	17
	Note 6 – Financial Instruments	18
	Note 7 – Inventories	21
	Note 8 – Property, Plant and Equipment	22
	Note 9 – Investments In and Advances to Unconsolidated Affiliates	23
	Note 10 – Business Combinations	26
	Note 11 – Intangible Assets and Goodwill	27
	Note 12 – Debt Obligations	29
	Note 13 – Member’s Equity	35
	Note 14 – Business Segments	36
	Note 15 – Related Party Transactions	37
	Note 16 – Income Taxes	44
	Note 17 – Commitments and Contingencies	45
	Note 18 – Significant Risks and Uncertainties	48
	Note 19 – Condensed Financial Information of EPO	50
	Note 20 – Subsequent Event	51

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, 2007. 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 the 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 28, 2008

ENTERPRISE PRODUCTS GP, LLC

CONSOLIDATED BALANCE SHEET

AT DECEMBER 31, 2007

(Dollars in thousands)

ASSETS
Current assets
	Cash and cash equivalents					$ 40,201
	Restricted cash					53,144
	Accounts and notes receivable - trade, net of allowance
			for doubtful accounts of $21,659			1,930,762
	Accounts receivable - related parties					79,700
	Inventories					354,282
	Prepaid and other current assets					80,195
					Total current assets	2,538,284
Property, plant and equipment, net						11,587,264
Investments in and advances to unconsolidated affiliates						858,339
Intangible assets, net of accumulated amortization of $341,494						917,000
Goodwill						591,652
Deferred tax asset						3,522
Other assets						112,346
					Total assets	$ 16,608,407

LIABILITIES AND MEMBER’S EQUITY
Current liabilities
	Accounts payable - trade					$ 324,999
	Accounts payable - related parties					26,393
	Accrued product payables					2,227,489
	Accrued expenses					47,756
	Accrued interest					130,971
	Other current liabilities					289,043
					Total current liabilities	3,046,651
Long-term debt: (see Note 12)
		Senior debt obligations – principal				5,646,500
		Junior subordinated notes – principal				1,250,000
		Other				9,645
				Total long-term debt		6,906,145
Deferred tax liabilities						21,362
Other long-term liabilities						73,856
Minority interest						6,020,193
Commitments and contingencies
Member’s equity						540,200
					Total liabilities and member's equity	$ 16,608,407

See Notes to Consolidated Balance Sheet.

ENTERPRISE PRODUCTS GP, LLC

NOTES TO CONSOLIDATED BALANCE SHEET

AT DECEMBER 31, 2007

Except per unit amounts, or 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.

Note 1. Company Organization

Company Organization

Enterprise Products GP, LLC is a Delaware limited liability company that was formed in May 1998 to become the general partner of Enterprise Products Partners L.P. The business purpose of Enterprise Products GP, LLC is to manage the affairs and operations of Enterprise Products Partners L.P. At December 31, 2007, Enterprise GP Holdings L.P. owned 100% of the membership interests of Enterprise Products GP, LLC.

Unless the context requires otherwise, references to “we,” “us,” “our” or “the Company” 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 Partners” mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries. Enterprise Products Partners is a publicly traded Delaware limited partnership, the registered common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” References to “EPGP” mean Enterprise Products GP, LLC, individually as the general partner of Enterprise Products Partners, and not on a consolidated basis. Enterprise Products Partners has no business activities outside those conducted by its operating subsidiary, Enterprise Products Operating LLC (“EPO”), as successor in interest by merger to Enterprise Products Operating L.P. Enterprise Products Partners and EPO were formed to acquire, own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO, Inc.

References to “Enterprise GP Holdings” mean the business and operations of Enterprise GP Holdings L.P. and its consolidated subsidiaries. Enterprise GP Holdings is a publicly traded Delaware limited partnership, the registered units of which are listed on the NYSE under the ticker symbol “EPE.” References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of Enterprise GP Holdings.

References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded affiliate, the common units of which are listed on the NYSE under the ticker symbol “TPP.” References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by Enterprise GP Holdings.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries. References to “LE GP” mean LE GP, LLC, which is the general partner of Energy Transfer Equity. On May 7, 2007, Enterprise GP Holdings acquired non-controlling interests in both LE GP and Energy Transfer Equity.

References to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”) and EPE Unit III, L.P. (“EPE Unit III”), collectively, which are private company affiliates of EPCO, Inc. See Note 20 for information regarding the formation of Enterprise Unit L.P. in February 2008.

On February 5, 2007, a consolidated subsidiary of EPO, Duncan Energy Partners L.P. (“Duncan Energy Partners”), completed an initial public offering of its common units (see Note 15). Duncan Energy Partners owns equity interests in certain of the midstream energy businesses of EPO. Duncan Energy

Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “DEP.” References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and a wholly owned subsidiary of EPO.

References to “EPCO” mean EPCO, Inc., which is a related party affiliate to all of the foregoing named entities. Dan L. Duncan is the Group Co-Chairman and controlling shareholder of EPCO.

For financial reporting purposes, Enterprise Products Partners consolidates the balance sheet of Duncan Energy Partners with that of its own. Enterprise Products Partners controls Duncan Energy Partners through the ownership of its general partner. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects Enterprise Products Partners’ historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners. Public ownership of Duncan Energy Partners’ net assets is presented as a component of minority interest in our consolidated balance sheet. The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, neither Enterprise Products Partners nor EPGP has any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

Basis of Presentation

EPGP owns a 2% general partner interest in Enterprise Products Partners, which conducts substantially all of its business. EPGP has 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 2 for additional information regarding minority interest in our consolidated subsidiaries.

Note 2. General Accounting Policies and Related Matters

Allowance for Doubtful Accounts

Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts. Our procedure for determining the allowance for doubtful accounts is based on (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research, and (iii) the levels of credit we grant to customers. In addition, we may increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts. Our allowance for doubtful accounts was $21.7 million at December 31, 2007.

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

We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. 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 also consolidate other entities and

ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership.

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

If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the entity’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the entity’s operating and financial policies. 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 balance sheet (or those of our equity method investments) in inventory or similar accounts. If our ownership interest in an entity does not provide us with either control or significant influence, we account for the investment using the cost method.

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us 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 management and legal counsel evaluate 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.

Current Assets and Current Liabilities

We present, as individual captions in our consolidated balance sheet, all components of current assets and current liabilities that exceed five percent of total current assets and liabilities, respectively.

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.

Environmental Costs

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies, and regulatory approvals.

The balance of our environmental liability associated with mercury gas meters was $17.2 million at December 31, 2007. At December 31, 2007 total reserves for environmental liabilities, including those related to the mercury gas meters were $26.5 million. At December 31, 2007 $6.3 million of this amount is classified as current liabilities on our Consolidated Balance Sheet.

Estimates

Preparing our Consolidated Balance Sheet in conformity with generally accepted accounting principles 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 our balance sheet. Our actual results could differ from these estimates. On an ongoing basis, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

Exchange Contracts

Exchanges are contractual agreements for the movements of NGLs and certain 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 product payables.

Receivables and payables arising from exchange transactions are settled with movements of products rather than with cash.

Financial Instruments

We use financial instruments such as swaps, forward and other contracts to manage price risks associated with inventories, firm commitments, interest rates, foreign currency and certain anticipated transactions. We recognize these transactions on our 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 incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item. If the financial instrument meets the criteria of a cash flow hedge, gains and losses incurred on the instrument are recorded in accumulated other comprehensive income (“AOCI”). Gains and losses on cash flow hedges are reclassified from accumulated 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 risk and the related 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 its inception and thereafter on a quarterly basis. Any hedge ineffectiveness is immediately recognized in earnings. See Note 6 for additional information regarding our financial instruments.

Foreign Currency Translation

We own a NGL marketing business located in Canada. The financial statements of this foreign subsidiary are translated into U.S. dollars from the Canadian dollar, which is the subsidiary’s functional currency, using the current rate method. Its assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, while revenue and expense items are translated at average rates of exchange

during the reporting period. Exchange gains and losses arising from foreign currency translation adjustments are reflected as separate components of AOCI in the accompanying Consolidated Balance Sheet. We attempt to hedge this currency risk (see Note 6).

Impairment Testing for Goodwill

Our goodwill amounts are assessed for impairment (i) on a routine annual basis or (ii) when impairment indicators are present. If such indicators occur (e.g., the loss of a significant customer, economic obsolescence of plant assets, etc.), the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its book value. If the fair value of the reporting unit exceeds its book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. See Note 11 for additional information regarding 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 when 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 asset carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. 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 price indicators or, in the absence of such data, appropriate valuation techniques.

Impairment Testing for Unconsolidated Affiliates

We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s industry. In the event we determine that the loss in value of an investment is other than a temporary decline, we record a charge to earnings to adjust the carrying value of the investment to its estimated fair value.

Income Taxes

Income taxes are primarily applicable to our state tax obligations under the Revised Texas Franchise Tax (“the Revised Texas Franchise Tax”) and certain federal and state tax obligations of Seminole Pipeline Company (“Seminole”) and Dixie Pipeline Company (“Dixie”), both of which are consolidated subsidiaries of ours. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, our tax status in the State of Texas has changed from non-taxable to taxable.

Since we are structured as a pass-through entity, we are not subject to federal income taxes. As a result, our member is individually responsible for paying federal income taxes on it’s share of our taxable

income. Since we do not have access to information regarding our member’s tax basis, we cannot readily determine the total difference in the basis of our net assets for financial and tax reporting purposes.

In accordance with Financial Accounting Standards Board Interpretation (“FIN”) 48, “Accounting for Uncertainty in Income Taxes,” we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. This guidance was effective January 1, 2007, and our adoption of this guidance had no material impact on our financial position. See Note 16 for additional information regarding our income taxes.

Inventories

Inventories primarily consist of NGLs, certain petrochemical products and natural gas volumes that 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 purchase from third parties or 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 (including freight-in charges that have been capitalized) 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 7 for additional information regarding our inventories.

Minority Interest

As presented in our Consolidated Balance Sheet, minority interest represents third-party and related party ownership interests in the net assets of our consolidated 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 and related party ownership in such amounts presented as minority interest. The following table presents the components of minority interest as presented on our Consolidated Balance Sheet at December 31, 2007:

Limited partners of Enterprise Products Partners:
Third-party owners of Enterprise Products Partners (1)	$ 5,011,701
Related party owners of Enterprise Products Partners (2)	578,074
Limited partners of Duncan Energy Partners:
Third-party owners of Duncan Energy Partners (3)	288,588
Joint venture partners (4)	141,830
Total minority interest on consolidated balance sheet	$ 6,020,193

(1) Consists of non-affiliate public unitholders of Enterprise Products Partners. (2) Consists of unitholders of Enterprise Products Partners that are related party affiliates. This group is primarily comprised of EPCO and certain of its private company consolidated subsidiaries. (3) Consists of non-affiliate public unitholders of Duncan Energy Partners. On February 5, 2007, Duncan Energy Partners completed its initial public offering of 14,950,000 common units. A wholly owned operating subsidiary of Enterprise Products Partners owns the general partner of Duncan Energy Partners; therefore, Enterprise Products Partners consolidates the financial statements of Duncan Energy Partners with those of its own. For financial accounting and reporting purposes, the public owners of Duncan Energy Partners are presented as minority interest in our consolidated financial statements effective February 1, 2007. (4) Represents third-party ownership interests in joint ventures that we consolidate, including Seminole, Dixie, Tri-States Pipeline L.L.C. (“Tri-States”), Independence Hub, LLC (“Independence Hub”), Wilprise Pipeline Company, L.L.C. (“Wilprise”) and Belle Rose NGL Pipeline, L.L.C. (“Belle Rose”).

Natural Gas Imbalances

In the natural gas pipeline transportation business, imbalances frequently result from differences in natural gas volumes received from and delivered to our customers. Such differences occur when a customer

delivers more or less gas into our pipelines than is physically redelivered back to them during a particular time period. We have various fee-based agreements with customers to transport their natural gas through our pipelines. Our customers retain ownership of their natural gas shipped through our pipelines. As such, our pipeline transportation activities are not intended to create physical volume differences that would result in significant accounting or economic events for either our customers or us during the course of the arrangement.

We settle pipeline gas imbalances through either (i) physical delivery of in-kind gas or (ii) in cash. These settlements follow contractual guidelines or common industry practices. As imbalances occur, they may be settled (i) on a monthly basis, (ii) at the end of the agreement or (iii) in accordance with industry practice, including negotiated settlements. Certain of our natural gas pipelines have a regulated tariff rate mechanism requiring customer imbalance settlements each month at current market prices.

However, the vast majority of our settlements are through in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an imbalance payable) or received from a customer (in the case of an imbalance receivable). Such in-kind deliveries are on-going and take place over several periods. In some cases, settlements of imbalances built up over a period of time are ultimately cashed out and are generally negotiated at values which approximate average market prices over a period of time. For those gas imbalances that are ultimately settled over future periods, we estimate the value of such current assets and liabilities using average market prices, which is representative of the estimated value of the imbalances upon final settlement. Changes in natural gas prices may impact our estimates.

At December 31, 2007 our natural gas imbalance receivables, net of allowance for doubtful accounts, was $60.9 million and is reflected as a component of “Accounts and notes receivable – trade” on our Consolidated Balance Sheet. At December 31, 2007 our imbalance payables was $38.3 million and is reflected as a component of “Accrued product payables” on our Consolidated Balance Sheet.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in the results of operations for the respective period. For financial statement purposes, depreciation is recorded based on the estimated useful lives of the related assets primarily using the straight-line method. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes. See Note 8 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 that benefit periods in excess of one year or for periods that are not determinable. We use the deferral method for our annual planned major maintenance activities.

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value (accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. To the extent we do not settle an ARO liability at our recorded amounts, we will incur a gain or loss.

Restricted Cash

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

Unit-Based Awards

We account for unit-based awards in accordance with SFAS 123(R), “Share-Based Payment.”

Note 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 157

SFAS 157, “Fair Value Measurements,” defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 applies only to fair-value measurements that are already required (or permitted) by other accounting standards and is expected to increase the consistency of those measurements. SFAS 157 emphasizes that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Companies will be required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop such measurements, and the effect of certain of the measurements on earnings (or changes in net assets) during a period.

Certain requirements of SFAS 157 are effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The effective date for other requirements of SFAS 157 has been deferred for one year. We adopted the provisions of SFAS 157 which are effective for fiscal years beginning after November 15, 2007 and there was no impact on our Consolidated Balance Sheet. Management is currently evaluating the impact that the deferred provisions of SFAS 157 will have on the disclosures in our Consolidated Balance Sheet in 2009.

SFAS 141(R)

SFAS 141(R), “Business Combinations,” replaces SFAS 141, “Business Combinations.” SFAS 141(R) retains the fundamental requirements of SFAS 141 that the acquisition method of accounting (previously termed the “purchase method”) be used for all business combinations and for an acquirer to be identified for each business combination. SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in a business combination and establishes the acquisition date as the date that the acquirer achieves control. This new guidance also retains guidance in SFAS 141 for identifying and recognizing intangible assets separately from goodwill.

The objective of SFAS 141(R) is to improve the relevance, representational faithfulness, and comparability of the information a reporting entity provides in its financial reports about business combinations and their effects. To accomplish this, SFAS 141(R) establishes principles and requirements for how the acquirer:

Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interests in the acquiree.

Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS 141(R) defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of

the consideration transferred plus any noncontrolling interest in the acquiree, and requires the acquirer to recognize that excess in earnings as a gain attributable to the acquirer.

Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.

SFAS 141(R) also requires that direct costs of an acquisition (e.g. finder’s fees, outside consultants, etc.) be expensed as incurred and not capitalized as part of the purchase price.

As a calendar year-end entity, we will adopt SFAS 141(R) on January 1, 2009. Although we are still evaluating this new guidance, we expect that it will have an impact on the way in which we evaluate acquisitions. For example, we have made several acquisitions in the past where the fair value of assets acquired and liabilities assumed was in excess of the purchase price. In those cases, a bargain purchase would have been recognized under SFAS 141(R). Conversely, we will no longer capitalize transaction fees and other direct costs.

SFAS 160

SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51,” establishes accounting and reporting standards for non-controlling interests, which have been referred to as minority interests in prior accounting literature. A noncontrolling interest is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent company. This new standard requires, among other things, that (i) ownership interests of noncontrolling interests be presented as a component of equity on the balance sheet (i.e. elimination of the mezzanine “minority interest” category); (ii) elimination of minority interest expense as a line item on the statement of income and, as a result, that net income be allocated between the parent and noncontrolling interests on the face of the statement of income; and (iii) enhanced disclosures regarding noncontrolling interests. As a calendar year-end entity, we will adopt SFAS 160 on January 1, 2009 and apply its presentation and disclosure requirements retrospectively.

Note 4. Accounting for Unit-Based Awards

See Note 20 for information regarding the formation of the Enterprise Products 2008 Long-Term Incentive Plan in January 2008 and Enterprise Unit L.P. in February 2008.

SFAS 123(R) requires us to recognize compensation expense related to unit-based awards based on the fair value of the award at grant date. The fair value of restricted unit awards (i.e. time-vested units under SFAS 123(R)) is based on the market price of the underlying common units on the date of grant. The fair value of other unit-based awards is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an equity-classified award (such as a restricted unit award) is amortized to earnings on a straight-line basis over the requisite service or vesting period. Compensation expense for liability-classified awards (such as unit appreciation rights (“UARs”)) is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. Liability-type awards are cash settled upon vesting.

As used in the context of the EPCO plans, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires.

1998 Plan

Unit option awards. Under the 1998 Plan, non-qualified incentive options to purchase a fixed number of Enterprise Product Partners’ common units may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. When issued, the exercise price of each option grant is equivalent to the market price of the underlying equity on the date of grant. In general,

options granted under the 1998 Plan have a cliff vesting period of four years and remain exercisable for ten years from the date of grant.

In order to fund its obligations under the 1998 Plan, EPCO may purchase common units at fair value either in the open market or directly from Enterprise Product Partners. When employees exercise unit options, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.

The fair value of each unit option is estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions including expected life of the options, risk-free interest rates, expected distribution yield on and expected unit price volatility of Enterprise Product Partners’ common units. In general, our assumption of expected life of the options represents the period of time that the options are expected to be outstanding based on an analysis of historical option activity. Our selection of the risk-free interest rate is based on published yields for U.S. government securities with comparable terms. The expected distribution yield and unit price volatility is estimated based on several factors, which include an analysis of Enterprise Product Partners’ historical unit price volatility and distribution yield over a period equal to the expected life of the option.

The 1998 Plan provides for the issuance of up to 7,000,000 of Enterprise Products Partners’ common units. After giving effect to outstanding option awards at December 31, 2007 and the issuance and forfeiture of restricted unit awards through December 31, 2007, a total of 1,282,256 additional common units could be issued under the 1998 Plan.

The following table presents option activity under the 1998 Plan for the year ended December 31, 2007:

				Weighted-
			Weighted-	average
			average	remaining	Aggregate
		Number of	strike price	contractual	Intrinsic
		Units	(dollars/unit)	term (in years)	Value (1)
Outstanding at December 31, 2006		2,416,000	$ 23.32
	Granted (2)	895,000	30.63
	Exercised	(256,000)	19.26
	Settled or forfeited (3)	(740,000)	24.62
Outstanding at December 31, 2007 (4)		2,315,000	26.18	7.73	$ 3,291
Options exercisable at:
	December 31, 2007 (4)	335,000	$ 22.06	3.96	$ 3,291

(1) Aggregate intrinsic value reflects fully vested unit options at the date indicated. (2) The total grant date fair value of these awards was $2.4 million based on the following assumptions: (i) expected life of options of seven years; (ii) weighted-average risk-free interest rate of 4.8%; (iii) weighted-average expected distribution yield on Enterprise Products Partners’ common units of 8.4%; and (iv) weighted-average expected unit price volatility on Enterprise Products Partners’ common units of 23.2%. (3) Includes the settlement of 710,000 options in connection with the resignation of our former chief executive officer. (4) We were committed to issue 2,315,000 of Enterprise Products Partners’ common units at December 31, 2007 if all outstanding options awarded under the 1998 Plan (as of these dates) were exercised. An additional 285,000, 380,000, 510,000 and 805,000 of these options are exercisable in 2008, 2009, 2010 and 2011, respectively.

The total intrinsic value of option awards exercised during the year ended December 31, 2007 was $3.0 million respectively. During the year ended December 31, 2007 we received cash of $7.5 million from the exercise of option awards granted under the 1998 Plan. Conversely, our option-related reimbursements to EPCO were $3.0 million.

Restricted unit awards. Under the 1998 Plan, we may also issue Enterprise Products Partners’ restricted common units to key employees of EPCO and directors of EPGP. In general, Enterprise Product Partners’ restricted unit awards allow recipients to acquire the underlying common units at no cost to the recipient once a defined cliff vesting period expires, subject to certain forfeiture provisions. The restrictions on such units generally lapse four years from the date of grant. Fair value of such restricted

units is based on the market price of the underlying common units on the date of grant and an allowance for estimated forfeitures.

The following table summarizes information regarding Enterprise Product Partners’ restricted unit awards for the year ended December 31, 2007:

			Weighted-
			Average Grant
		Number of	Date Fair Value
		Units	per Unit (1)
Restricted units at December 31, 2006		1,105,237
	Granted (2)	738,040	$ 25.61
	Vested	(4,884)	$ 25.28
	Forfeited	(36,800)	$ 23.51
	Settled (3)	(113,053)	$ 23.24
Restricted units at December 31, 2007		1,688,540

(1) Determined by dividing the aggregate grant date fair value of awards (including an allowance for forfeitures) by the number of awards issued. (2) Aggregate grant date fair value of restricted unit awards issued during 2007 was $18.9 million based on grant date market prices of Enterprise Products Partners’ common units ranging from $28.00 to $31.83 per unit and estimated forfeiture rates ranging from 4.6% to 17.0%. (3) Reflects the settlement of restricted units in connection with the resignation of our former chief executive officer.

The total fair value of Enterprise Products Partners’ restricted units that vested during the year ended December 31, 2007 was $0.1 million.

Phantom unit awards. The 1998 Plan also provides for the issuance of Enterprise Product Partners’ phantom unit awards. These liability awards are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at redemption dates in each award. The fair market value of each phantom unit award is equal to the market closing price of Enterprise Product Partners’ common units on the redemption date. Each participant is required to redeem their phantom units as they vest, which typically is four years from the date the award is granted. No phantom unit awards have been issued to date under the 1998 Plan.

The 1998 Plan also provides for the award of distribution equivalent rights (“DERs”) in tandem with its phantom unit awards. A DER entitles the participant to cash distributions equal to the product of the number of phantom units outstanding for the participant and the cash distribution rate paid by Enterprise Products Partners to its unitholders.

Employee Partnerships

EPCO formed the Employee Partnerships to serve as an incentive arrangement for key employees of EPCO by providing them a “profits interest” in the Employee Partnerships. Certain EPCO employees who work on behalf of us and EPCO were issued Class B limited partner interests and admitted as Class B limited partners without any capital contribution. The profits interest awards (i.e., the Class B limited partner interests) in the Employee Partnerships entitles each holder to participate in the appreciation in value of Enterprise GP Holdings’ Units. The Class B limited partner interests are subject to forfeiture if the participating employee’s employment with EPCO is terminated prior to vesting, with customary exceptions for death, disability and certain retirements. The risk of forfeiture will also lapse upon certain change in control events.

A portion of the fair value of these equity-based awards is allocated to us under the EPCO administrative services agreement as a non-cash expense. We are not responsible for reimbursing EPCO for any expenses of the Employee Partnerships, including the value of any contributions of cash or units of Enterprise GP Holdings made by private company affiliates of EPCO at the formation of each Employee Partnership.

Currently, there are four Employee Partnerships. EPE Unit I was formed in August 2005 in connection with Enterprise GP Holdings’ initial public offering. EPE Unit II was formed in December 2006. EPE Unit III was formed in May 2007. Enterprise Unit L.P. was formed in February 2008 (see Note 20).

The following is a discussion of significant terms of EPE Unit I, EPE Unit II, and EPE Unit III.

EPE Unit I. In connection with the initial public offering of Enterprise GP Holdings in August 2005, EPE Unit I was formed to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in EPE Unit I. In August 2005, EPE Unit I used $51.0 million in contributions it received from its Class A limited partner (an affiliate of EPCO) to purchase 1,821,428 units of Enterprise GP Holdings. Certain EPCO employees, including all of EPGP’s executive officers other than Dan L. Duncan and Dr. Ralph S. Cunningham, were admitted as Class B limited partners of EPE Unit I without any capital contributions.

Unless otherwise agreed to by EPCO, the Class A limited partner and a majority of the Class B limited partners, EPE Unit I will be liquidated upon the earlier of (i) August 2010 or (ii) a change in control of Enterprise GP Holdings or its general partner, EPE Holdings. Upon liquidation of EPE Unit I, units having a fair market value equal to the Class A limited partner’s capital base, plus any Class A preferred return for the quarter in which liquidation occurs, will be distributed to the Class A limited partner. Any remaining units will be distributed to the Class B limited partners as a residual profits interest award in EPE Unit I.

As adjusted for forfeitures and regrants, the grant date fair value of the Class B limited partnership interests in EPE Unit I was $12.2 million at December 31, 2007. This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards ranging from three to five years, (ii) risk-free interest rates ranging from 4.1% to 5.0%, (iii) an expected distribution yield on units of Enterprise GP Holdings ranging from 3.0% to 4.2%, and (iv) an expected unit price volatility for Enterprise GP Holdings’ units ranging from 17.4% to 30.0%.

EPE Unit II. In December 2006, EPE Unit II was formed to serve as an incentive arrangement for Dr. Ralph S. Cunningham, an executive officer of EPGP. The officer, who is not a participant in EPE Unit I, was granted a “profits interest” award in EPE Unit II. EPCO serves as the general partner of EPE Unit II.

At inception, EPE Unit II used $1.5 million in contributions it received from an affiliate of EPCO (which was admitted as the Class A limited partner of EPE Unit II as a result of such contribution) to purchase 40,725 units of Enterprise GP Holdings at an average price of $36.91 per unit in December 2006. The officer was issued a Class B limited partner interest in EPE Unit II without any capital contribution.

Unless otherwise agreed upon by EPCO, the Class A limited partner and the Class B limited partner, EPE Unit II will be liquidated upon the earlier of (i) December 2011 or (ii) a change in control of Enterprise GP Holdings or its general partner, EPE Holdings. Upon liquidation of the EPE Unit II, units having a fair market value equal to the Class A limited partner’s capital base will be distributed to the Class A limited partner, plus any Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partner as a residual profits interest award in EPE Unit II.

The grant date fair value of the Class B limited partnership interests in EPE Unit II was $0.2 million at December 31, 2007. This fair value was estimated on the date of grant using the Black-Scholes option pricing model, which incorporated various assumptions including (i) an expected life of the award of five years, (ii) risk-free interest rate of 4.4%, (iii) an expected distribution yield on units of Enterprise GP Holdings of 3.8%, and (iv) an expected Enterprise GP Holdings unit price volatility of 18.7%.

EPE Unit III. EPE Unit III owns 4,421,326 units of Enterprise GP Holdings contributed to it by a private company affiliate of EPCO, which, in turn, was made the Class A limited partner of EPE Unit III.

The units of Enterprise GP Holdings contributed by the Class A limited partner had a fair value of $170.0 million on the date of contribution (the “Class A limited partner capital base”). Certain EPCO employees were issued Class B limited partner interests and admitted as Class B limited partners of EPE Unit III without any capital contribution. The profits interest awards (i.e., Class B limited partner interests) in EPE Unit III entitle the holder to participate in the appreciation in value of Enterprise GP Holdings’ units owned by EPE Unit III.

Unless otherwise agreed to by EPCO, the Class A limited partner and a majority in interest of the Class B limited partners of EPE Unit III, EPE Unit III will be liquidated upon the earlier of: (i) May 7, 2012 or (ii) a change in control of Enterprise GP Holdings or its general partner. EPE Unit III has the following material terms regarding its quarterly cash distribution to partners:

Distributions of Cash flow – Each quarter, 100% of the cash distributions received by EPE Unit III from Enterprise GP Holdings will be distributed to the Class A limited partner until it has received an amount equal to the pro rata Class A preferred return (as defined below), and any remaining distributions received by EPE Unit III will be distributed to the Class B limited partners. The Class A preferred return equals 3.797% per annum, of the Class A limited partner’s capital base. The Class A limited partner’s capital base equals approximately $170.0 million plus any unpaid Class A preferred return from prior periods, less any distributions made by EPE Unit III of proceeds from the sale of Enterprise GP Holdings’ units owned by EPE Unit III (as described below).

Liquidating Distributions – Upon liquidation of EPE Unit III, Enterprise GP Holdings’ units having a fair market value equal to the Class A limited partner capital base will be distributed to a private company affiliate of EPCO, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining units of Enterprise GP Holdings will be distributed to the Class B limited partners.

Sale Proceeds – If EPE Unit III sells any of the 4,421,326 units of Enterprise GP Holdings that it owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above.

The Class B limited partner interests in EPE Unit III 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 May 7, 2012, with customary exceptions for death, disability and certain retirements. The risk of forfeiture associated with the Class B limited partner interests in EPE Unit III will also lapse upon certain change of control events.

As adjusted for forfeitures and regrants, the grant date fair value of the Class B limited partnership interests in EPE Unit III was $23.0 million at December 31, 2007. This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards ranging from four to five years, (ii) risk-free interest rates ranging from 3.5% to 4.9%, (iii) an expected distribution yield on units of Enterprise GP Holdings ranging from 4.0% to 4.3%, and (iv) an expected unit price volatility for Enterprise GP Holdings’ units ranging from 16.9% to 17.6%.

DEP Holdings, LLC Unit Appreciation Rights

The non-employee directors of DEP GP have been granted UARs in the form of letter agreements. These liability awards are not part of any established long-term incentive plan of EPCO, Enterprise GP Holdings or us. The compensation expense associated with these awards is recognized by DEP GP, which is our consolidated subsidiary. The UARs entitle each non-employee director to receive a cash payment on the vesting date equal to the excess, if any, of the fair market value of Enterprise GP Holdings’ units (determined as of a future vesting date) over the grant date fair value. If a director resigns prior to vesting, his UAR awards are forfeited. These UARs are accounted for similar to liability awards under SFAS 123(R) since they will be settled with cash.

As of December 31, 2007, a total of 90,000 UARs had been granted to non-employee directors of DEP GP that cliff vest in 2012. If a director resigns prior to vesting, his UAR awards are forfeited. The grant date fair value with respect to these UARs is based on an Enterprise GP Holdings’ unit price of $36.68.

Note 5. Employee Benefit Plans

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 for the year ended December 31, 2007.

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 presents Dixie’s benefit obligations, fair value of plan assets and funded status at December 31, 2007.

	Pension	Postretirement
	Plan	Plan
Projected benefit obligation	$ 7,250	$ 5,882
Accumulated benefit obligation	4,971	--
Fair value of plan assets	5,572	--
Funded status (liability)	1,678	5,882

Projected benefit obligations and net periodic benefit costs are based on actuarial estimates and assumptions. The weighted-average actuarial assumptions used in determining the projected benefit obligation at December 31, 2007 were as follows: discount rate of 5.75%; rate of compensation increase of 4.00% and 5.00% for the pension and postretirement plans, respectively; and a medical trend rate of 8.00% for 2008 grading to an ultimate trend of 5.00% for 2010 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
2008	$ 218	$ 389
2009	287	422
2010	324	467
2011	518	505
2012	534	497
2013 through 2017	3,779	2,353
Total	$ 5,660	$ 4,633

On December 31, 2006, Dixie adopted the recognition and disclosure provisions of SFAS 158. Dixie uses a December 31 measurement date for these plans. SFAS 158 requires Dixie to recognize the

funded status of its defined benefit pension and other postretirement plans as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income.

Note 6. Financial Instruments

We are exposed to financial market risks, including changes in commodity prices, interest rates and foreign exchange rates. In addition, we are exposed to fluctuations in exchange rates between the U.S. dollar and Canadian dollar. 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 (i) the variability of future earnings, (ii) fair values of certain debt instruments and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates.

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, interest rate or exchange 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 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 hedging criteria. When this occurs, we may enter into a new financial instrument to reestablish the hedge to which the closed instrument relates.

Interest Rate Risk Hedging Program

Our interest rate exposure results from variable and fixed rate borrowings under various debt agreements. 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. The following information summarizes significant components of our interest rate risk hedging portfolio:

Fair value hedges – Interest rate swaps

As summarized in the following table, Enterprise Products Partners had eleven interest rate swap agreements outstanding at December 31, 2007 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 8.65%	$50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013	2	Jan. 2004 to Feb. 2013	Feb. 2013	6.38% to 7.19%	$200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014	6	4th Qtr. 2004 to Oct. 2014	Oct. 2014	5.60% to 6.13%	$600 million
Senior Notes K, 4.95% fixed rate, due June 2010	2	Aug. 2005 to June 2010	June 2010	4.95% to 5.33%	$200 million
(1) The variable rate indicated is the all-in variable rate for the current settlement period.

We have designated these eleven 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, 2007, was an asset of $14.8 million, with an offsetting decrease in the fair value of the underlying debt.

Cash flow hedges – Interest Rate Swaps

Duncan Energy Partners had three interest rate swap agreements outstanding at December 31, 2007 that were accounted for as cash flow hedges.

		Number	Period Covered	Termination	Variable to	Notional
Hedged Variable Rate Debt		Of Swaps	by Swap	Date of Swap	Fixed Rate (1)	Value
Duncan Energy Partners’ Revolver, due Feb. 2011		3	Sep. 2007 to Sep. 2010	Sep. 2010	4.84% to 4.62%	$175.0 million

	(1) Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).

In September 2007, Duncan Energy Partners executed three floating-to-fixed interest rate swaps having a combined notional value of $175.0 million. The purpose of these financial instruments is to reduce the sensitivity of Duncan Energy Partners’ earnings to variable interest rates charged under its revolving credit facility.

At December 31, 2007, the aggregate fair value of these interest rate swaps was a liability of $3.8 million. As cash flow hedges, any increase or decrease in fair value (to the extent effective) is recorded into other comprehensive income and amortized into income based on the settlement period hedged. Any ineffectiveness is recorded directly into earnings as an increase in interest expense.

Cash flow hedges – Treasury locks

At times, we may use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to our anticipated issuances of debt. A treasury lock is a specialized agreement that fixes the price (or yield) on a specific treasury security for an established period of time. A treasury lock purchaser is protected from a rise in the yield of the underlying treasury security during the lock period. Each of the treasury lock transactions was designated as a cash flow hedge under SFAS 133.

To the extent effective, gains and losses on the value of the treasury locks will be deferred until the forecasted debt is issued and will be amortized to earnings over the life of the debt. No ineffectiveness was recognized as of December 31, 2007. Gains or losses on the termination of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-

rate debt. The following table summarizes changes in our treasury lock portfolio since December 31, 2006 (dollars in millions):

					Notional
					Amount
Treasury lock portfolio, December 31, 2006					$ 562.5
First quarter of 2007 additions to portfolio (1)					437.5
Second quarter of 2007 terminations (3)					(875.0)
Third quarter of 2007 additions to portfolio (4)					875.0
Third quarter of 2007 terminations (5)					(750.0)
Fourth quarter of 2007 additions to portfolio (6)					350.0
Treasury lock portfolio, December 31, 2007 (2)					$ 600.0

(1) EPO entered into these transactions related to its anticipated issuances of debt in 2007. (2) The fair value of open financial instruments at December 31, 2007 was a liability of $19.6 million. (3) Terminations relate to the issuance of the Junior Notes B ($500.0 million) and Senior Notes L ($375.0 million). (4) EPO entered into these transactions related to its issuance of the Senior Notes L (including its successor debt) in August 2007 ($500.0 million) and anticipated issuance of debt during the first half of 2008 ($250.0 million). (5) Terminations relate to the issuance of the Senior Notes L and its successor debt. (6) EPO entered into these transactions in anticipated issuance of debt during the first half of 2008.

Commodity Risk Hedging Program

The prices of natural gas, NGLs and certain 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 price risks associated with such products, 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) the value of 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, NGLs or certain petrochemical products. From time to time, we inject natural gas into storage and utilize hedging instruments to lock in the value of our inventory positions. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.

The fair value of our commodity financial instrument portfolio, which primarily consisted of cash flow hedges, at December 31, 2007 was a liability of $19.3 million. These contracts will terminate during 2008.

Foreign Currency Hedging Program

We are exposed to foreign currency exchange rate risk through our Canadian NGL marketing subsidiary and certain construction agreements with respect to our Pioneer processing plant where payments are indexed to the Canadian dollar. As a result, we could be adversely affected by fluctuations in the foreign currency exchange rate between the U.S. dollar and the Canadian dollar. We attempt to hedge this risk using foreign exchange purchase contracts to fix the exchange rate.

Mark-to-market accounting is utilized for those foreign exchange contracts associated with our Canadian NGL marketing business. The duration of these contracts is typically one month. As of December 31, 2007, $4.7 million of these exchange contracts were outstanding, all of which settled in January 2008.

The foreign exchange contracts associated with our construction activities are accounted for using hedge accounting. At December 31, 2007, the fair value of these contracts was $1.3 million. These contracts settle through May 2008.

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. The following table presents the estimated fair values of our financial instruments at December 31, 2007:

		Carrying	Fair
Financial Instruments		Value	Value
Financial assets:
	Cash and cash equivalents	$ 93,345	$ 93,345
	Accounts receivable	2,010,462	2,010,462
	Commodity financial instruments (1)	338	338
	Foreign currency hedging financial instruments (2)	1,308	1,308
	Interest rate hedging financial instruments (3)	14,839	14,839
Financial liabilities:
	Accounts payable and accrued expenses	2,757,608	2,757,608
	Fixed-rate debt (principal amount)	5,904,000	5,867,899
	Variable-rate debt	992,500	992,500
	Commodity financial instruments (1)	19,643	19,643
	Foreign currency hedging financial instruments (2)	27	27
	Interest rate hedging financial instruments (3)	23,422	23,422

(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) Relates to the hedging of our exposure to fluctuations in the Canadian dollar. (3) 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.

Note 7. Inventories

Our inventory amounts were as follows at December 31, 2007:

Working inventory (1)	$ 342,589
Forward-sales inventory (2)	11,693
Total inventory	$ 354,282

(1) Working inventory is comprised of inventories of natural gas, NGLs and certain petrochemical products that are either available-for-sale or used in the provision for services. (2) Forward sales inventory consists of segregated NGL and natural gas volumes dedicated to the fulfillment of forward-sales contracts.

Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs. We value our inventories at the lower of average cost or market.

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. 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.

Due to fluctuating commodity prices in the NGL, natural gas and petrochemical industry, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value.

Note 8. Property, Plant and Equipment

Our property, plant and equipment values and accumulated depreciation balances were as follows at December 31, 2007:

	Estimated
	Useful Life
	in Years
Plants and pipelines (1)	3-35 (5)	$ 10,884,819
Underground and other storage facilities (2)	5-35 (6)	720,795
Platforms and facilities (3)	23-31	637,812
Transportation equipment (4)	3-10	32,627
Land		48,172
Construction in progress		1,173,988
Total		13,498,213
Less accumulated depreciation		1,910,949
Property, plant and equipment, net		$ 11,587,264

(1) Plants and pipelines include 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 include underground product storage caverns; storage tanks; water wells; and related assets. (3) Platforms and facilities include 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 as follows: 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 as follows: 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 recorded $75.5 million of capitalized interest during the year ended December 31, 2007.

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.

The following table presents information regarding our asset retirement obligations since December 31, 2006.

Asset retirement obligation liability balance, December 31, 2006	$ 24,403
Liabilities incurred	1,673
Liabilities settled	(5,069)
Revisions in estimated cash flows	15,645
Accretion expense	3,962
Asset retirement obligation liability balance, December 31, 2007	$ 40,614

Property, plant and equipment at December 31, 2007 $10.6 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, 2007 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our Consolidated Balance Sheet.

Note 9. Investments In and Advances to Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method of accounting. Our investments in and advances to unconsolidated affiliates are grouped according to the business segment to which they relate. See Note 14 for a general discussion of our business segments. The following table shows our investments in and advances to unconsolidated affiliates at December 31, 2007:

		Ownership
		Percentage
NGL Pipelines & Services:
	VESCO	13.1%	$ 40,129
	K/D/S Promix, L.L.C. (“Promix”)	50%	51,537
	Baton Rouge Fractionators LLC (“BRF”)	32.3%	25,423
Onshore Natural Gas Pipelines & Services:
	Jonah Gas Gathering Company (“Jonah”)	19.4%	235,837
	Evangeline (1)	49.5%	3,490
Offshore Pipelines & Services:
	Poseidon Oil Pipeline, L.L.C. (“Poseidon”)	36%	58,423
	Cameron Highway Oil Pipeline Company (“Cameron Highway”) (2)	50%	256,588
	Deepwater Gateway, L.L.C. (“Deepwater Gateway”)	50%	111,221
	Neptune Pipeline Company, L.L.C. (“Neptune”)	25.7%	55,468
	Nemo Gathering Company, LLC (“Nemo”) (3)	33.9%	2,888
Petrochemical Services:
	Baton Rouge Propylene Concentrator, LLC (“BRPC”)	30%	13,282
	La Porte (4)	50%	4,053
Total			$ 858,339

(1) Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2) The December 31, 2007 amount includes a $216.5 million contribution to Cameron Highway to fund our portion of the repayment of Cameron Highway’s debt. (3) The December 31, 2007 amount includes a $7.0 million non-cash impairment charge attributable to our investment in Nemo. (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 a company exceeds the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates. At December 31, 2007 our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway, Nemo and Jonah included excess cost amounts totaling $43.8 million, all of which were attributable to the fair value of the underlying tangible assets of these entities exceeding their book carrying values at the time of our acquisition of interests in these entities.

NGL Pipelines & Services

At December 31, 2007, 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 facility and related assets located in south Louisiana.

Promix. We own a 50.0% 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, 2007 of this segment’s current unconsolidated affiliates are summarized below.

Current assets		$ 112,352
Property, plant and equipment, net		270,586
Other assets		11,686
	Total assets	$ 394,624

Current liabilities		$ 75,314
Other liabilities		9,095
Combined equity		310,215
	Total liabilities and combined equity	$ 394,624

Onshore Natural Gas Pipelines & Services

At December 31, 2007, our Onshore Natural Gas Pipelines & Services segment 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 located in south Louisiana. A subsidiary of Acadian Gas, LLC owns the Evangeline interests, which were contributed to Duncan Energy Partners in February 2007 in connection with its initial public offering (see Note 15).

Jonah. Our equity interest in Jonah at December 31, 2007 is based on capital contributions we made to Jonah in connection with its Phase V expansion project through this date. We completed Phase I of this expansion in July 2007 entitling us to approximately 19.4% in earnings and ownership with the remaining 80.6% entitlement to TEPPCO. See Note 15 for additional information regarding our Jonah affiliate. Jonah owns the Jonah Gas Gathering System located in the Greater Green River Basin of southwestern Wyoming.

The combined balance sheet information at December 31, 2007 of this segment’s current unconsolidated affiliates is summarized below.

Current assets		$ 83,962
Property, plant and equipment, net		915,572
Other assets		176,091
	Total assets	$ 1,175,625

Current liabilities		$ 43,951
Other liabilities		25,002
Combined equity		1,106,672
	Total liabilities and combined equity	$ 1,175,625

Offshore Pipelines & Services

At December 31, 2007, our Offshore Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

Poseidon. We own a 36.0% 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 50.0% 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.

Cameron Highway repaid its $365.0 million Series A notes and $50.0 million Series B notes in 2007 using cash contributions from its partners. We funded our 50% share of the capital contributions using borrowings under EPO’s Multi-Year Revolving Credit Facility.

Deepwater Gateway. We own a 50.0% interest in Deepwater Gateway, which owns the Marco Polo platform located in the Gulf of Mexico. The Marco Polo platform processes crude oil and natural gas production from the Marco Polo, K2, K2 North and Ghengis 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 and Nautilus Systems, 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, 2007 of this segment’s current unconsolidated affiliates is summarized below.

Current assets		$ 46,795
Property, plant and equipment, net		1,122,108
Other assets		4,338
	Total assets	$ 1,173,241

Current liabilities		$ 19,720
Other liabilities		96,791
Combined equity		1,056,730
	Total liabilities and combined equity	$ 1,173,241

Nemo was formed in 1999 to construct, own and operate the Nemo Gathering System, a 24-mile natural gas gathering system in the Gulf of Mexico offshore Louisiana. The Nemo Gathering System, which began operations in 2001, gathers natural gas from certain developments in the Green Canyon area of the Gulf of Mexico to a pipeline interconnect with the Manta Ray Gathering System. Due to a recent decrease in throughput volumes on the Nemo Gathering System, we evaluated our 33.9% investment in Nemo for impairment during the second quarter of 2007. The decrease in throughput volumes is primarily due to underperformance of certain fields and natural depletion.

Our review of Nemo’s estimated future cash flows during the second quarter of 2007 indicated that the carrying value of our investment exceeded its fair value, which resulted in a non-cash impairment charge of $7.0 million. After recording this impairment charge, the carrying value of our investment in Nemo at December 31, 2007 was $2.9 million.

Our investment in Nemo was written down to fair value, which management estimated using recognized business valuation techniques. The fair value analysis is based upon management’s expectation of future cash flows, which incorporates certain industry information and assumptions made by management. For example, the individual reviews of Nemo included management estimates regarding natural gas reserves of producers served by Nemo. If the assumptions underlying our fair value analysis change and expected cash flows are reduced, additional impairment charges may result.

Petrochemical Services

At December 31, 2007, our Petrochemical Services segment included the following unconsolidated affiliates accounted for using the equity method:

BRPC. We own a 30.0% interest in BRPC, which owns a propylene fractionation facility located in south Louisiana.

La Porte. We own an aggregate 50.0% interest in La Porte, which owns a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas.

The combined balance sheet information at December 31, 2007 of this segment’s current unconsolidated affiliates is summarized below.

Current assets		$ 3,187
Property, plant and equipment, net		47,322
	Total assets	$ 50,509

Current liabilities		$ 970
Other liabilities		2
Combined equity		49,537
	Total liabilities and combined equity	$ 50,509

Note 10. Business Combinations

Our expenditures for business combination during the year ended December 31, 2007 were $35.8 million, which primarily reflect the $35.0 million we spent to acquire the South Monco natural gas pipeline business (“South Monco”) in December 2007. This business includes approximately 128 miles of natural gas pipelines located in southeast Texas. The remaining business combination-related amounts for 2007 consist of purchase price adjustments to prior period transactions.

We accounted for our 2007 business combinations using the purchase method of accounting and, accordingly, such costs have been allocated to assets acquired and liabilities assumed based on estimated preliminary fair values. Such preliminary values have been developed using recognized business valuation techniques and are subject to change pending a final valuation analysis. We expect to finalize the purchase price allocations for these transactions during 2008.

			South Monco
			Acquisition	Other	Total
Assets acquired in business combination:
	Property, plant and equipment, net		$ 36,000	$ 8,386	$ 44,386
	Intangible assets		--	(8,460)	(8,460)
		Total assets acquired	36,000	(74)	35,926
Liabilities assumed in business combination:
	Other long-term liabilities		(1,000)	(244)	(1,244)
		Total liabilities assumed	(1,000)	(244)	(1,244)
		Total assets acquired less liabilities assumed	35,000	(318)	34,682
		Total cash used for business combinations	35,000	793	35,793
Goodwill			$ --	$ 1,111	$ 1,111

Note 11. Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets at December 31, 2007:

		Gross	Accum.	Carrying
		Value	Amort.	Value
NGL Pipelines & Services:
	Shell Processing Agreement	$ 206,216	$ (78,252)	$ 127,964
	Encinal gas processing customer relationship	127,119	(17,470)	109,649
	STMA and GulfTerra NGL Business
	customer relationships	49,784	(17,537)	32,247
	Pioneer gas processing contracts	37,752	(736)	37,016
	Markham NGL storage contracts	32,664	(14,154)	18,510
	Toca-Western contracts	31,229	(8,718)	22,511
	Piceance Creek customer relationship	--	--	--
	Other	35,261	(10,087)	25,174
	Segment total	520,025	(146,954)	373,071
Onshore Natural Gas Pipelines & Services:
	San Juan Gathering System customer relationships	331,311	(73,087)	258,224
	Petal & Hattiesburg natural gas storage contracts	100,499	(27,931)	72,568
	Other	31,741	(8,381)	23,360
	Segment total	463,551	(109,399)	354,152
Offshore Pipelines & Services:
	Offshore pipeline & platform customer relationships	205,845	(73,905)	131,940
	Other	1,167	(49)	1,118
	Segment total	207,012	(73,954)	133,058
Petrochemical Services:
	Mont Belvieu propylene fractionation contracts	53,000	(8,960)	44,040
	Other	14,906	(2,227)	12,679
	Segment total	67,906	(11,187)	56,719
	Total all segments	$ 1,258,494	$ (341,494)	$ 917,000

We paid $11.2 million for certain air emission credits related to our Mont Belvieu complex in 2007. These items were recorded as intangible assets within our Petrochemical Services business segment.

In general, our intangible assets fall within two categories – contract-based intangible assets and customer relationships. Contract-based intangible assets represent commercial rights we acquired in connection with business combinations or asset purchases. Customer relationship intangible assets represent customer bases that we acquired in connection with business combinations and asset purchases. The values assigned to intangible assets are amortized to earnings using either (i) a straight-line approach or (ii) other methods that closely resemble the pattern in which the economic benefits of associated resource bases are estimated to be consumed or otherwise used, as appropriate.

The intangible assets we acquired in connection with the Encinal acquisition represent the value we assigned to customer relationships, particularly the long-term relationship we now have with Lewis Energy Group, L.P. through natural gas processing and gathering arrangements. These intangible assets will be amortized to earnings over a 20-year life using methods that closely resemble the pattern in which we estimate the depletion of the underlying natural gas resources to occur.

We acquired numerous customer relationship and contract-based intangible assets in connection with the September 2004 merger with GulfTerra Energy Partners, L.P. (“GulfTerra Merger”). The customer relationship intangible assets represent the exploration and production, natural gas processing and NGL fractionation customer bases served by GulfTerra and the South Texas midstream assets at the time the merger was completed. The contract-based intangible assets represent the rights we acquired in connection with discrete contracts to provide storage services for natural gas and NGLs that GulfTerra had entered into prior to the merger.

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 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 (iv) STMA and GulfTerra NGL Business customer relationships.

The contract-based intangible assets we acquired in connection with the GulfTerra Merger 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.

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 purchase 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.

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, 2007:

NGL Pipelines & Services
	GulfTerra Merger		$ 23,854
	Acquisition of Indian Springs natural gas processing business		13,162
	Encinal acquisition		95,280
	Other		21,410
Onshore Natural Gas Pipelines & Services
	GulfTerra Merger		279,956
	Acquisition of Indian Springs natural gas gathering business		2,165
Offshore Pipelines & Services
	GulfTerra Merger		82,135
Petrochemical Services
	Acquisition of Mont Belvieu propylene fractionation business		73,690
		Total	$ 591,652

Goodwill recorded in connection with 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 could develop (such as reduced general and administrative costs and interest savings) that would result in improved financial results for the merged entity. Based on miles of pipelines, GulfTerra was one of the largest natural gas gathering and transportation companies in the United States, serving producers in the central and western Gulf of Mexico and onshore in Texas and New Mexico. These regions offer us significant growth potential through the acquisition and construction of additional pipelines, platforms, processing and storage facilities and other midstream energy infrastructure.

We recorded an increase in our goodwill in connection with the Encinal acquisition. Management attributes this goodwill to potential future benefits we may realize from our other south Texas processing and NGL businesses as a result of acquiring the Encinal business. Specifically, our acquisition of the long-term dedication rights associated with the Encinal business is expected to add value to our south Texas processing facilities and related NGL businesses due to increased volumes. The Encinal goodwill is

recorded as part of the NGL Pipelines & Services business segment due to management’s belief that such future benefits will accrue to businesses classified within this segment.

The remainder of our goodwill amounts is associated with prior acquisitions, principally that of our purchase of a propylene fractionation business in February 2002 and our acquisition of indirect ownership interests in the Indian Springs natural gas gathering and processing business in January 2005.

Note 12. Debt Obligations

Our consolidated debt obligations consisted of the following at December 31, 2007:

EPO senior debt obligations:
	Multi-Year Revolving Credit Facility, variable rate, due November 2012 (1)		$ 725,000
	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 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		250,000
	Senior Notes J, 5.75% fixed-rate, due March 2035		250,000
	Senior Notes K, 4.950% fixed-rate, due June 2010		500,000
	Senior Notes L, 6.30% fixed-rate, due September 2017		800,000
	Petal GO Zone Bonds, variable rate, due August 2034		57,500
Duncan Energy Partners’ debt obligation:
	$300 Million Revolving Credit Facility, variable rate, due February 2011		200,000
Dixie Revolving Credit Facility, variable rate, due June 2010			10,000
		Total principal amount of senior debt obligations	5,646,500
EPO Junior Subordinated Notes A, due August 2066			550,000
EPO Junior Subordinated Notes B, due January 2068			700,000
Total principal amount of senior and junior debt obligations			6,896,500
Other, including unamortized discounts and premiums and changes in fair value (2)			9,645
		Long-term debt	$ 6,906,145

Standby letters of credit outstanding			$ 1,100

(1) In November 2007, EPO executed an amended and restated revolving credit agreement governing its Multi-Year Revolving Credit Facility. This new credit agreement increases the capacity from $1.25 billion to $1.75 billion and extends the maturity date of amounts borrowed under EPO’s Multi-Year Revolving Credit Facility from October 2011 to November 2012. (2) The amount includes an asset of $14.8 million related to fair value hedges offset by a net $5.2 million in unamortized discounts.

Letters of credit

At December 31, 2007, we had $1.1 million of standby letters outstanding under Duncan Energy Partners’ Revolving Credit Facility.

Enterprise Products Partners-Subsidiary guarantor relationships

Enterprise Products Partners act as guarantor of the debt obligations of EPO with the exception of the Dixie revolving credit facility. If EPO were to default on any debt we guarantee, Enterprise Products Partners would be responsible for full repayment of that obligation. Enterprise Products Partners does not act as guarantor of the debt obligations of Duncan Energy Partners.

EPO's senior indebtedness is structurally subordinated to and ranks junior in right of payment to the indebtedness of Dixie. This subordination feature exists only to the extent that the repayment of debt

incurred by Dixie is dependent upon the assets and operations of this entity. The Dixie revolving credit facility is an unsecured obligation of Dixie (of which we own 74.2% of its capital stock).

EPO’s debt obligations

Multi-Year Revolving Credit Facility. In November 2007, EPO executed an amended and restated Multi-Year Revolving Credit Facility totaling $1.75 billion, which replaced an existing $1.25 billion multi-year revolving credit agreement. Amounts borrowed under the amended and restated credit agreement mature in November 2012, although EPO is permitted, 30 to 60 days before the maturity date in effect, to convert the principal balance of the revolving loans then outstanding into a non-revolving, one-year term loan (the “term-out option”). There is no sublimit on the amount of standby letters of credit that can be outstanding under the amended facility. EPO’s borrowings under this agreement are unsecured general obligations that are non-recourse to EPGP. 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 bear interest at a Eurodollar rate plus an applicable margin. In addition, EPO is required to pay a quarterly facility fee on each lender’s commitment irrespective of commitment usage.

The applicable margins will be increased by 0.100% per annum for each day that the total outstanding loans and letter of credit obligations under the facility exceeds fifty percent of the total lender commitments. Also, upon the conversion of the revolving loans to term loans pursuant to the term-out option described above, the applicable margin will increase by 0.125% per annum and, if immediately prior to such conversion, the total amount of outstanding loans and letter of credit obligations under the facility exceeds fifty percent of the total lender commitments, the applicable margin with respect to the term loans will increase by an additional 0.10% per annum.

EPO may increase the amount that may be borrowed under the facility, without the consent of the lenders, by an amount not exceeding $500.0 million by adding to the facility one or more new lenders and/or requesting that the commitments of existing lenders be increased, although none of the existing lenders has agreed to or is obligated to increase its existing commitment. EPO may request unlimited one-year extensions of the maturity date by delivering a written request to the administrative agent, but any such extension shall be effective only if consented to by the required lenders in their sole discretion.

The Multi-Year Revolving Credit Facility contains various covenants related to EPO’s ability to incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; and make certain investments. The loan agreement also requires EPO to satisfy certain financial covenants at the end of each fiscal quarter. The credit agreement also restricts EPO’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 in 2000, EPO 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 EPO’s credit rating by Moody’s declines below Baa3 in combination with our credit rating at Standard & Poor’s declining below BBB-, 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 L. These fixed-rate notes are unsecured obligations of EPO and rank equally with its existing and future unsecured and unsubordinated indebtedness. They are senior to any future subordinated indebtedness. EPO’s borrowings under these notes are non-recourse to EPGP. 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 EPGP. The Senior Notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict EPO’s ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

EPO used net proceeds from its issuance of Senior Notes L to temporarily reduce indebtedness outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. In October 2007, EPO used borrowing capacity under its Multi-Year Revolving Credit Facility to repay its $500.0 million Senior Notes E.

Petal GO Zone Bonds. In August 2007, Petal Gas Storage L.L.C. (“Petal”), a wholly owned subsidiary of EPO, borrowed $57.5 million from the MBFC pursuant to a loan agreement and promissory note between Petal and the MBFC to pay a portion of the costs of certain natural gas storage facilities located in Petal, Mississippi. The promissory note between Petal and MBFC is guaranteed by EPO and supported by a letter of credit issued by Petal. On the same date, the MBFC issued $57.5 million in Gulf Opportunity Zone Tax-Exempt (“GO Zone”) bonds to various third parties. A portion of the GO Zone bond proceeds are being held by a third party trustee and reflected as a component of other assets on our balance sheet. The remaining proceeds held by the trustee will be released to us as we spend capital to complete the construction of the natural gas storage facilities. At December 31, 2007, $17.9 million of the GO Zone bond proceeds remained held by the third party trustee. The promissory note and the GO Zone bonds have identical terms including floating interest rates and maturities of twenty-seven years. The bonds and the associated tax incentives are authorized under the Mississippi Business Finance Act and the Gulf Opportunity Zone Act of 2005.

Petal MBFC Loan. In August 2007, Petal entered into a loan agreement and a promissory note with the MBFC under which Petal may borrow up to $29.5 million. On the same date, the MBFC issued taxable bonds to EPO in the maximum amount of $29.5 million. As of December 31, 2007, there was $8.9 million outstanding under the loan and the bonds. EPO will make advances on the bonds to the MBFC and the MBFC will in turn make identical advances to Petal under the promissory note. The promissory note and the taxable bonds have identical terms including fixed interest rates of 5.90% and maturities of fifteen years. The bonds and the associated tax incentives are authorized under the Mississippi Business Finance Act. Petal may prepay on the promissory note without penalty, and thus cause the bonds to be redeemed, any time after one year from their date of issue. The loan and bonds are netted in preparing our consolidated balance sheet.

Junior Notes A. These fixed/floating, unsecured, long-term subordinated notes are due 2066 (“Junior Notes A”). EPO used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. EPO’s payment obligations under Junior Notes A are subordinated to all of its current and future senior indebtedness (as defined in the related indenture agreement). Enterprise Products Partners guaranteed EPO’s repayment of amounts due under Junior Notes A through an unsecured and subordinated guarantee.

The indenture agreement governing Junior Notes A allows EPO to defer interest payments on one or more occasions for up to ten consecutive years, subject to certain conditions. The indenture agreement also provides that, unless (i) all deferred interest on Junior Notes A has been paid in full as of the most recent interest payment date, (ii) no event of default under the indenture agreement has occurred and is continuing and (iii) Enterprise Products Partners is not in default of its obligations under related guarantee agreements, neither Enterprise Products Partners nor EPO cannot declare or make any distributions to any of their respective equity securities or make any payments on indebtedness or other obligations that rank pari passu with or are subordinated to the Junior Notes A.

The Junior Notes A bear interest at a fixed annual rate of 8.375% from July 2006 to August 2016, payable semi-annually in arrears in February and August of each year, which commenced in February 2007. After August 2016, the Junior Notes A will bear variable rate interest at an annual rate equal to the 3-month LIBOR rate for the related interest period plus 3.708%, payable quarterly in arrears in February, May, August and November of each year commencing in November 2016. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to the certain provisions. The Junior Notes A mature in August 2066 and are not redeemable by EPO prior to August 2016 without payment of a make-whole premium.

In connection with the issuance of Junior Notes A, EPO entered into a Replacement Capital Covenant in favor of the covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed for the benefit of such debt holders that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the of issuance of certain securities.

Junior Notes B. EPO sold $700 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due January 2068 (“Junior Notes B”) during the second quarter of 2007. EPO used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. EPO’s payment obligations under Junior Notes B are subordinated to all of its current and future senior indebtedness (as defined in the Indenture Agreement). Enterprise Products Partners has guaranteed repayment of amounts due under Junior Notes B through an unsecured and subordinated guarantee.

The indenture agreement governing Junior Notes B allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. During any period in which interest payments are deferred and subject to certain exceptions, neither Enterprise Products Partners nor EPO can declare or make any distributions to any of their respective equity securities or make any payments on indebtedness or other obligations that rank pari passu with or are subordinate to Junior Notes B. Junior Notes B rank pari passu with Junior Notes A.

The Junior Notes B will bear interest at a fixed annual rate of 7.034% through January 15, 2018, payable semi-annually in arrears in January and July of each year, commencing in January 2008. After January 2018, the Junior Notes B will bear variable rate interest at the greater of (1) the sum of the 3-month LIBOR for the related interest period plus a spread of 268 basis points or (2) 7.034% per annum, payable quarterly in arrears in January, April, July and October of each year commencing in April 2018. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to certain provisions. The Junior Notes B mature in January 2068 and are not redeemable by EPO prior to January 2018 without payment of a make-whole premium.

In connection with the issuance of Junior Notes B, Enterprise Products Partners and EPO entered into a Replacement Capital Covenant in favor of the covered debt holders (as named therein) pursuant to which they agreed for the benefit of such debt holders that neither Enterprise Products Partners nor EPO would redeem or repurchase such junior notes on or before January 15, 2038, unless such redemption or repurchase is made from the proceeds of issuance of certain securities.

Duncan Energy Partners’ debt obligation

The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, neither Enterprise Products Partners nor EPGP has any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

Duncan Energy Partners entered into a $300.0 million revolving credit facility, all of which may be used for letters of credit, with a $30.0 million sublimit for Swingline loans. Letters of credit outstanding under this facility reduce the amount available for borrowings. At the closing of its initial public offering, Duncan Energy Partners made its initial borrowing of $200.0 million under the facility to fund a $198.9 million cash distribution to EPO and the remainder to pay debt issuance costs. At December 31, 2007, the principal balance outstanding under this facility was $200.0 million.

This credit facility matures in February 2011 and will be used by Duncan Energy Partners in the future to fund working capital and other capital requirements and for general partnership purposes. Duncan Energy Partners may make up to two requests for one-year extensions of the maturity date (subject to certain restrictions). The revolving credit facility is available to pay distributions upon the initial contribution of assets to Duncan Energy Partners, fund working capital, make acquisitions and provide payment for general purposes. Duncan Energy Partners can increase the revolving credit facility, without consent of the lenders, by an amount not to exceed $150.0 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders. No existing lender is required to increase its commitment, unless it agrees to do so in its sole discretion.

This revolving credit facility offers the following unsecured loans, each having different interest requirements: (i) LIBOR loans bear interest at a rate per annum equal to LIBOR plus the applicable LIBOR margin (as defined in the credit agreement), (ii) Base Rate loans bear interest at a rate per annum equal to the higher of (a) the rate of interest publicly announced by the administrative agent, Wachovia Bank, National Association, as its Base Rate and (b) 0.5% per annum above the Federal Funds Rate in effect on such date and (iii) Swingline loans bear interest at a rate per annum equal to LIBOR plus an applicable LIBOR margin.

The Duncan Energy Partners’ credit facility contains certain financial and other customary covenants. Also, if an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity date of amounts borrowed under the credit agreement and exercise other rights and remedies.

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. In accordance with GAAP, we consolidate the debt of Dixie with that of our own; however Enterprise Products Partners does not have the obligation to make interest or debt payments with respect to Dixie’s debt. Dixie’s debt obligations consist of a senior, unsecured revolving credit facility having a borrowing capacity of $28.0 million.

As defined in the Dixie 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 plus ½%.

The 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.

Canadian Debt Obligations

In May 2007, Canadian Enterprise Gas Products, Ltd. (“Canadian Enterprise”), a wholly-owned subsidiary of EPO, entered into a $30.0 million Canadian revolving credit facility with The Bank of Nova Scotia. The credit facility, which includes the issuance of letters of credit, matures in October 2011. Letters of credit outstanding under this facility reduce the amount available for borrowings.

Borrowings may be made in Canadian or U.S. dollars. Canadian denominated borrowings may be comprised of Canadian Prime Rate (“CPR”) loans or Bankers’ Acceptances and U.S. denominated borrowings may be comprised of Alternative Base Rate (“ABR”) or Eurodollar loans, each having different interest rate requirements. CPR loans bear interest at a rate determined by reference to the Canadian Prime Rate. ABR loans bear interest at a rate determined by reference to an alternative base rate as defined in the credit agreement. Eurodollar loans bear interest at a rate determined by the LIBOR plus an applicable rate

as defined in the credit agreement. Bankers’ Acceptances carry interest at the rate for Canadian bankers’ acceptances plus an applicable rate as defined in the credit agreement.

The credit facility contains customary covenants and events of default. The restrictive covenants limit Canadian Enterprise from materially changing the nature of its business or operations, dissolving, or completing mergers. A continuing event of default would accelerate the maturity of amounts borrowed under the credit facility. The obligations under the credit facility are guaranteed by EPO. As of December 31, 2007, there were no debt obligations outstanding under this credit facility.

Covenants

We are in compliance with the covenants of our consolidated debt agreements at December 31, 2007.

Information regarding variable interest rates paid

The following table shows the range of interest rates paid and weighted-average interest rate paid on our consolidated variable-rate debt obligations during the year ended December 31, 2007.

	Range of	Weighted-average
	interest rates	interest rate
	paid	paid
EPO’s Multi-Year Revolving Credit Facility	5.10% to 8.25%	5.78%
Duncan Energy Partners’ Revolving Credit Facility	5.52% to 6.42%	6.23%
Dixie Revolving Credit Facility	5.50% to 5.67%	5.63%
Canadian Enterprise Revolving Credit Facility	5.01% to 5.82%	5.68%
Petal GO Zone Bonds	3.11% to 4.15%	3.56%

Consolidated debt maturity table

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

2008	$ --
2009	500,000
2010	591,840
2011	650,000
2012	697,160
Thereafter	4,457,500
Total scheduled principal payments	$ 6,896,500

Debt Obligations of Unconsolidated Affiliates

We have two unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at December 31, 2007, (ii) total debt of each unconsolidated affiliate at December 31, 2007 (on a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities of such debt.

	Our		Scheduled Maturities of Debt
	Ownership							After
	Interest	Total	2008	2009	2010	2011	2012	2012
Poseidon	36%	$ 91,000	$ --	$ --	$ --	$ 91,000	$ --	$ --
Evangeline	49.5%	20,650	5,000	5,000	10,650	--	--	--
Total		$ 111,650	$ 5,000	$ 5,000	$ 10,650	$ 91,000	$ --	$ --

The credit agreements of our unconsolidated affiliates contain various affirmative and negative covenants, including financial covenants. These businesses were in compliance with such covenants at

December 31, 2007. The credit agreements of our unconsolidated affiliates 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. Cameron Highway repaid its debt obligations during the second quarter of 2007 using pro rata capital contributions from EPO and its joint venture partner in Cameron Highway.

The following information summarizes significant terms of the debt obligations of our unconsolidated affiliates at December 31, 2007:

Poseidon. Poseidon has $91.0 million outstanding under its $150.0 million revolving credit facility that matures in May 2011. 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 rates charged on this debt at December 31, 2007 was 6.62%.

Evangeline. At December 31, 2007, short and long-term debt for Evangeline consisted of (i) $13.2 million in principal amount of 9.90% 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 $5.0 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 noteholders 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 rates charged on this note at December 31, 2007 was 5.88%. Accrued interest payable related to the subordinated note was $9.1 million at December 31, 2007.

Note 13. Member’s Equity

At December 31, 2007, member’s equity consisted of the capital account of Enterprise GP Holdings, and AOCI. 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 the ticker symbol “EPE.”

Accumulated other comprehensive income

The following table summarizes transactions affecting our AOCI since December 31, 2006.

	Cash Flow Hedges					Accumulated
		Interest		Foreign	Pension	Other
	Commodity	Rate	Foreign	Currency	And	Comprehensive
	Financial	Financial	Currency	Translation	Postretirement	Income
	Instruments	Instruments	Hedges	Adjustment	Plans	Balance
Balance, December 31, 2006	$ (3,622)	$ 26,034	$ --	$ (807)	$ (464)	$ 21,141
Net commodity financial instrument gains during period	(17,997)	--	--	--	--	(17,997)
Net interest rate financial instrument gains during period	--	14,375	--	--	--	14,375
Amortization of cash flow financing hedges	--	(5,429)	--	--	--	(5,429)
Change in funded status of pension and postretirement
plans, net of tax	--	--	--	--	1,052	1,052
Foreign currency hedge gain	--	--	1,308	--	--	1,308
Foreign currency translation adjustment	--	--	--	2,007	--	2,007
Balance, December 31, 2007	$ (21,619)	$ 34,980	$ 1,308	$ 1,200	$ 588	$ 16,457

Note 14. Business 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 technologies employed) and products produced and/or sold.

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, crude oil and certain petrochemicals. In general, hydrocarbons enter our asset system in a number of ways, such as an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an onshore natural gas gathering pipeline, an NGL fractionator, an NGL storage facility, or an NGL transportation or distribution pipeline.

Many of our equity investees are included within our integrated midstream asset system. For example, we have ownership interests in several offshore natural gas and crude oil pipelines. Other examples include our use of the Promix NGL fractionator to process mixed NGLs extracted by our gas plants. The fractionated NGLs we receive from Promix can then be sold in our NGL marketing activities.

The majority of our plant-based operations are located in Texas, Louisiana, Mississippi, New Mexico and Wyoming. Our natural gas, NGL and crude oil pipelines are located in a number of regions of the United States including (i) the Gulf of Mexico offshore Texas and Louisiana; (ii) the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and (iii) certain regions of the central and western United States, including the Rocky Mountains. 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 assigned to each segment on the basis of each asset’s or investment’s principal operations. The principal reconciling difference between consolidated property, plant and equipment and the total value of segment assets is construction-in-progress. Segment assets represent the net book carrying value of facilities and other assets that contribute to gross operating margin of that particular segment. Since assets under construction generally do not contribute to segment gross operating margin, such assets are excluded from segment asset totals until they are placed in service. Consolidated intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate.

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

			Reportable Segments
				Onshore
			NGL	Natural Gas	Offshore		Adjustments
			Pipelines	Pipelines	Pipelines	Petrochemical	and	Consolidated
			& Services	& Services	& Services	Services	Eliminations	Totals
Segment assets:
		At December 31, 2007	$ 4,570,555	$ 3,702,297	$ 1,452,568	$ 687,856	$ 1,173,988	$ 11,587,264
Investments in and advances to
	unconsolidated affiliates (see Note 9):
		At December 31, 2007	117,089	239,327	484,588	17,335	--	858,339
Intangible Assets (see Note 11):
		At December 31, 2007	373,071	354,152	133,058	56,719	--	917,000
Goodwill (see Note 11):
		At December 31, 2007	153,706	282,121	82,135	73,690	--	591,652

Note 15. Related Party Transactions

We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.

Relationship with EPCO and affiliates

We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities that are not a part of our consolidated group of companies:

EPCO and its private company subsidiaries;

Enterprise GP Holdings, which owns and controls EPGP;

TEPPCO, which is owned and controlled by Enterprise GP Holdings;

the Employee Partnerships (see Note 4); and

Energy Transfer Equity, an equity method investment of Enterprise GP Holdings.

We also have an ongoing relationship with Duncan Energy Partners, the balance sheet of which is consolidated with that of our own. A description of our relationship with Duncan Energy Partners is presented within this Note 15.

EPCO is a private company controlled by Dan L. Duncan, who is also a Director and Chairman of EPGP. At December 31, 2007, EPCO and its affiliates beneficially owned 147,986,045 (or 34.0%) of Enterprise Products Partners’ outstanding common units, which includes 13,454,498 of Enterprise Products Partners’ common units owned by Enterprise GP Holdings. In addition, at December 31, 2007, EPCO and its affiliates beneficially owned 77.1% of the limited partner interests of Enterprise GP Holdings and 100% of its general partner, EPE Holdings. Enterprise GP Holdings owns all of the membership interests of EPGP. The principal business activity of EPGP is to act as Enterprise Products Partners’ managing partner. The executive officers and certain of the directors of EPGP and EPE Holdings are employees of EPCO.

In connection with its general partner interest in Enterprise Products Partners, EPGP received cash distributions of $124.4 million from Enterprise Products Partners during the year ended December 31, 2007. This amount includes incentive distributions of $107.4 million for the year ended December 31, 2007.

Enterprise Products Partners and EPGP are both separate legal entities apart from each other and apart from EPCO, Enterprise GP Holdings and their respective other affiliates, with assets and liabilities that are separate from those of EPCO, Enterprise GP Holdings and their respective other affiliates. EPCO and its private company subsidiaries and affiliates depend on the cash distributions they receive from Enterprise Products Partners, Enterprise GP Holdings and other investments to fund their other operations and to meet their debt obligations. EPCO and its private company affiliates received $355.5 million in cash distributions from Enterprise Products Partners and Enterprise GP Holdings during the year ended December 31, 2007.

The ownership interests in Enterprise Products Partners that are owned or controlled by Enterprise GP Holdings are pledged as security under its credit facility. In addition, substantially all of the ownership interests in Enterprise Products Partners that are owned or controlled by EPCO and its affiliates, other than those interests owned by Enterprise GP Holdings, Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of a private company affiliate of EPCO. This credit facility contains customary and other events of default relating to EPCO and certain affiliates, including Enterprise GP Holdings, TEPPCO and Enterprise Products Partners.

We have entered into an agreement with EPCO to provide trucking services to us for the transportation of NGLs and other products. We lease office space in various buildings from affiliates of EPCO. The rental rates in these lease agreements approximate market rates.

EPCO Administrative Services Agreement

We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to an administrative services agreement (the “ASA”). We, Duncan Energy Partners, Enterprise GP Holdings, TEPPCO and their respective general partners are parties to the ASA. The significant terms of the ASA are as follows:

EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our businesses, properties and assets (all 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 will allow us to participate as named insureds in its overall insurance program, with the associated premiums and other costs being allocated 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. We record the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to members’ equity accounted for as a general contribution to us. At December 31, 2007, 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, our general and administrative costs include amounts we reimburse to 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 reimbursements were $56.5 million during the year ended December 31, 2007.

The ASA also addresses potential conflicts that may arise among us, Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), and the EPCO Group. The EPCO Group includes EPCO and its other affiliates, but excludes Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners and their respective general partners. With respect to potential conflicts, the ASA provides, among other things, that:

If a business opportunity to acquire “equity securities” (as defined below) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), then Enterprise GP Holdings will have the first right to pursue such opportunity. The term “equity securities” is defined to include:

general partner interests (or securities which have characteristics similar to general partner interests) 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.

Enterprise GP Holdings will be presumed to want to acquire the equity securities until such time as EPE Holdings advises the EPCO Group, EPGP and DEP GP that it has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to equal or 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, Conflicts and Governance Committee (“ACG Committee”) of EPE Holdings. If the purchase price is reasonably likely to be less than $100 million, the Chief Executive Officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings.

In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, EPGP and DEP GP, Enterprise Products Partners will have the second right to pursue such acquisition. Enterprise Products Partners will be presumed to want to acquire the equity securities until such time as EPGP advises the EPCO Group and DEP GP 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 EPGP’s Chief Executive Officer and ACG Committee.

In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition.

In the event Enterprise Products Partners abandons the acquisition opportunity for the equity securities and so notifies the EPCO Group and DEP GP, the EPCO Group may pursue the acquisition or offer the opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates, in either case, 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 (i.e. not involving “equity securities”) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), or Duncan Energy Partners (including DEP GP), Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan Energy Partners. It will be presumed that Enterprise Products Partners will pursue the business opportunity until such time as EPGP advises the EPCO Group, EPE Holdings and DEP GP that it has abandoned the pursuit of such business opportunity.

In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100 million, any decision to decline the business opportunity will be made by the Chief Executive Officer of EPGP after consultation with and subject to the approval of the ACG Committee of EPGP. If the purchase price or cost is reasonably likely to be less than $100 million, the Chief Executive Officer of EPGP may make the determination to decline the business opportunity without consulting EPGP’s ACG Committee.

In the event that Enterprise Products Partners abandons the business opportunity for itself and Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the second right to pursue such business opportunity. It will be presumed that Enterprise GP Holdings will pursue such acquisition until such time as its general partner declines such opportunity (in accordance with the procedures described above for Enterprise Products Partners) and advises the EPCO Group that it has abandoned the pursuit of such business opportunity. Should this occur, the EPCO Group may either pursue the business opportunity or offer the business opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates.

None of Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or their respective general partners or the EPCO Group have any obligation to present business opportunities to TEPPCO (including TEPPCO GP) or their controlled affiliates. Likewise, TEPPCO (including TEPPCO GP) and their controlled affiliates have no obligation to present business opportunities to Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or their respective general partners or the EPCO Group.

Relationship with TEPPCO

TEPPCO became a related party to us in February 2005 in connection with the acquisition of TEPPCO GP by a private company subsidiary of EPCO. In May 2007, Enterprise GP Holdings purchased TEPPCO GP from this private company subsidiary of EPCO.

Jonah Joint Venture with TEPPCO. In August 2006, we became a joint venture partner with TEPPCO in Jonah, which owns the Jonah Gas Gathering System located in the Greater Green River Basin of southwestern Wyoming. The Jonah Gathering System gathers and transports natural gas produced from the Jonah and Pinedale fields to regional natural gas processing plants and major interstate pipelines that deliver natural gas to end-user markets.

Prior to entering into the Jonah joint venture, we managed the construction of the Phase V expansion and funded the initial construction costs under a letter of intent we entered into in February 2006. In connection with the joint venture arrangement, we and TEPPCO plan to continue the Phase V expansion, which is expected to increase the capacity of the Jonah Gathering System from 1.5 Bcf/d to 2.4 Bcf/d and to significantly reduce system operating pressures, which we anticipate will lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which has increased

the system gathering capacity to 2.0 Bcf/d, was completed in July 2007 and the final phase of this expansion is expected to be completed by April 2008. The total anticipated cost of the Phase V expansion is expected to be approximately $505.0 million. We continue to manage the Phase V construction project.

Since August 1, 2006, we and TEPPCO have equally shared in the construction costs of the Phase V expansion. TEPPCO has reimbursed us $261.6 million, which represents 50% of total Phase V costs incurred through December 31, 2007. We had a receivable of $9.9 million from TEPPCO at December 31, 2007 for Phase V expansion costs.

TEPPCO was entitled to all distributions from the joint venture until specified milestones were achieved, at which point, we became entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. Since the first phase of this expansion was reached in July 2007, we and TEPPCO have shared earnings based on a formula that takes into account our respective capital contributions, including expenditures by TEPPCO prior to the expansion.

At December 31, 2007, we owned an approximate 19.4% interest in Jonah and TEPPCO owns 80.6%. We operate the Jonah system. We account for our investment in the Jonah joint venture using the equity method.

The Jonah joint venture is governed by a management committee comprised of two representatives approved by us and two appointed by TEPPCO, each with equal voting power. After an in-depth consideration of all relevant factors, this transaction was approved by the ACG Committee of EPGP and the Audit and Conflicts Committee of the general partner of TEPPCO. The ACG Committee of EPGP received a fairness opinion in connection with this transaction. The transaction was reviewed and recommended for approval by the Audit and Conflicts Committee of TEPPCO GP with assistance from an independent financial advisor.

We have agreed to indemnify TEPPCO from any and all losses, claims, demands, suits, liabilities, costs and expenses arising out of or related to breaches of our representations, warranties, or covenants related to the Jonah joint venture. A claim for indemnification cannot be filed until the losses suffered by TEPPCO exceed $1.0 million. The maximum potential amount of future payments under the indemnity agreement is limited to $100.0 million. All indemnity payments are net of insurance recoveries that TEPPCO may receive from third-party insurance carriers. We carry insurance coverage that may offset any payments required under the indemnification.

Purchase and lease of pipelines for DEP South Texas NGL Pipeline System from TEPPCO. In January 2007, we purchased a 10-mile segment of pipeline from TEPPCO located in the Houston area for $8.0 million. This pipeline segment is part of the DEP South Texas NGL Pipeline System that commenced operations in January 2007. In addition, we entered into a lease with TEPPCO for an 11-mile interconnecting pipeline located in the Houston area that is part of the DEP South Texas NGL Pipeline System. Although the primary term of the lease expired in September 2007, it is being renewed on a month-to-month basis until construction of a parallel pipeline is completed in early 2008. These transactions were in accordance with the Board-approved management authorization policy.

Relationship with Energy Transfer Equity

Enterprise GP Holdings acquired equity method investments in Energy Transfer Equity and its general partner in May 2007. As a result, Energy Transfer Equity and its consolidated subsidiaries became related parties to our consolidated businesses.

We have a long-term revenue generating contract with Titan Energy Partners, L.P. (“Titan”), a consolidated subsidiary of Energy Transfer Partners, L.P. (“ETP”). Titan purchases substantially all of its propane requirements from us. The contract continues until March 31, 2010 and contains renewal and extension options. We and Energy Transfer Company (“ETC OLP”) transport natural gas on each other’s systems and share operating expenses on certain pipelines. ETC OLP also sells natural gas to us.

Relationships with Unconsolidated Affiliates

Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. See Note 9 of the Notes to Consolidated Financial Statements for a discussion of this alignment of commercial interests. Since we and our affiliates hold ownership interests in these entities and directly or indirectly benefit from our related party transactions with such entities, they are presented here.

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. In addition, we furnished $1.1 million in letters of credit on behalf of Evangeline at December 31, 2007.

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

We perform management services for certain of our unconsolidated affiliates.

Relationship with Duncan Energy Partners

On February 5, 2007, Duncan Energy Partners completed its initial public offering of 14,950,000 common units at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of $290.5 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of these net proceeds to Enterprise Products Partners (along with $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units of Duncan Energy Partners). Duncan Energy Partners used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units it had originally issued to Enterprise Products Partners, resulting in the final amount of 5,351,571 common units beneficially owned by Enterprise Products Partners. Enterprise Products Partners used the cash received from Duncan Energy Partners to temporarily reduce amounts outstanding under EPO’s Multi-Year Revolving Credit Facility.

In addition to the 34% direct ownership interest we retained in certain subsidiaries of Duncan Energy Partners, Enterprise Products Partners also own the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units. EPO directs the business operations of Duncan Energy Partners through its control of Duncan Holdings, LLC (“DEP GP”). Certain of our officers and directors are also beneficial owners of common units of Duncan Energy Partners.

For financial reporting purposes, Enterprise Products Partners consolidates the balance sheet of Duncan Energy Partners with that of its own. In turn, we consolidate the balance sheet of Enterprise Products Partners with our own. All intercompany transactions between Enterprise Products Partners and Duncan Energy Partners are eliminated in the preparation of Enterprise Products Partners’ consolidated balance sheet. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects Enterprise Products Partners’ historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners. Public ownership of Duncan Energy Partners’ net assets is presented as a component of minority interest in our consolidated balance sheet.

Enterprise Products Partners has significant involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions: (i) we utilize storage services provided by Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”) to support our Mont Belvieu fractionation and

other businesses; (ii) we buy natural gas from and sell natural gas to Acadian Gas, LLC (“Acadian Gas”) in connection with our normal business activities; and (iii) we are the sole shipper on the DEP South Texas NGL Pipeline System.

Enterprise Products Partners may contribute other equity interests in its subsidiaries to Duncan Energy Partners in the near term and use the proceeds it receives from Duncan Energy Partners to fund its capital spending program.

Omnibus Agreement. On February 5, 2007, EPO and Duncan Energy Partners entered into an Omnibus Agreement that governs its relationship with Duncan Energy Partners on the following matters:

indemnification for certain environmental liabilities, tax liabilities and right-of-way defects;

reimbursement of certain expenditures incurred by DEP South Texas NGL and Mont Belvieu Caverns;

a right of first refusal to EPO in Duncan Energy Partners’ current and future subsidiaries and a right of first refusal on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business; and

a preemptive right with respect to equity securities issued by certain of Duncan Energy Partners’ subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.

EPO has indemnified Duncan Energy Partners against certain pre-February 2007 environmental and related liabilities associated with the assets EPO contributed to Duncan Energy Partners at the time of its initial public offering. These liabilities include both known and unknown environmental and related liabilities. This indemnification obligation will terminate on February 5, 2010. There is an aggregate cap of $15.0 million on the amount of indemnity coverage. In addition, Duncan Energy Partners is not entitled to indemnification until the aggregate amount of claims it incurs exceeds $250 thousand. Liabilities resulting from a change of law after February 5, 2007 are excluded from the EPO environmental indemnity. In addition, EPO has indemnified Duncan Energy Partners for liabilities related to:

certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to Duncan Energy Partners in connection with its initial public offering are located and failure to obtain certain consents and permits necessary to conduct its business that arise through February 5, 2010; and

certain income tax liabilities attributable to the operation of the assets contributed to Duncan Energy Partners in connection with its initial public offering prior to February 5, 2007.

The Omnibus Agreement may not be amended without the prior approval of the ACG Committee if the proposed amendment will, in the reasonable discretion of DEP GP, adversely affect holders of the it’s common units.

Neither Enterprise Products Partners, nor EPO and any of its affiliates are restricted under the Omnibus Agreement from competing with Duncan Energy Partners. Except as otherwise expressly agreed in the EPCO administrative services agreement, EPO and any of its affiliates may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer Duncan Energy Partners the opportunity to purchase or construct those assets. These agreements are in addition to other agreements relating to business opportunities and potential conflicts of interest set forth in the administrative services agreement with EPO, EPCO and other affiliates of EPCO.

In certain cases, EPO is responsible for funding 100% of project costs rather than sharing such costs with Duncan Energy Partners in accordance with the existing sharing ratio of 66% funded by Duncan Energy Partners and 34% funded by EPO. Under the Omnibus Agreement, EPO agreed to make additional

contributions to Duncan Energy Partners as reimbursement for Duncan Energy Partners’ 66% share of any excess project costs above (i) the $28.6 million of estimated project costs to complete the Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated project costs for additional Mont Belvieu brine production capacity and above-ground storage reservoir projects. These projects were in progress at the time of Duncan Energy Partners’ initial public offering. In December 2007, EPO made cash contributions totaling $9.9 million to Duncan Energy Partners’ subsidiaries in connection with the Omnibus Agreement.

In December 2007, EPO made an additional $38.1 million cash contribution to Mont Belvieu Caverns for capital expenditures in which Duncan Energy Partners is not a participant. This contribution was in accordance with provisions of the Mont Belvieu Caverns’ limited liability company agreement, which states that when Duncan Energy Partners elects to not participate in certain projects, then EPO is responsible for funding 100% of such projects. To the extent such non-participated projects generate incremental earnings for Mont Belvieu Caverns in the future, the sharing ratio for Mont Belvieu Caverns will be adjusted to allocate such incremental cash flows to EPO. Under the terms of the agreement, Duncan Energy Partners may elect to reacquire for consideration a 66% share of these projects at a later date.

Note 16. Income Taxes

Our income taxes relate primarily to federal and state income taxes of Seminole and Dixie, our two largest corporations subject to such income taxes. In addition, with the amendment of the Texas Franchise Tax in 2006, we have become a taxable entity in the state of Texas.

Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2007 are as follows:

Deferred Tax Assets:
Net operating loss carryovers	$ 23,270
Credit carryover	26
Charitable contribution carryover	16
Employee benefit plans	3,214
Deferred revenue	642
Reserve for legal fees and damages	478
Equity investment in partnerships	409
Asset retirement obligation	80
Accruals	1,068
Total Deferred Tax Assets	29,203
Valuation allowance	(5,345)
Net Deferred Tax Assets	23,858
Deferred Tax Liabilities:
Property, plant and equipment	40,520
Other	99
Total Deferred Tax Liabilities	40,619
Total Net Deferred Tax Liabilities	$ (16,761)

Current portion of total net deferred tax assets	$ 1,081
Long-term portion of total net deferred tax liabilities	$ (17,842)

We had net operating loss carryovers of $23.3 million at December 31, 2007. These losses expire in various years between 2008 and 2028 and are subject to limitations on their utilization. We record a valuation allowance to reduce our deferred tax assets to the amount of future tax benefit that is more likely than not to be realized. The valuation allowance was $5.3 million at December 31, 2007 and serves to reduce the recognized tax benefit associated with carryovers of our corporate entities to an amount that will, more likely than not, be realized.

On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.

Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Due to the enactment of the Revised Texas Franchise Tax, we recorded a net deferred tax liability of $3.8 million during the year ended December 31, 2007.

Note 17. Commitments and Contingencies

Litigation

On occasion, we or our unconsolidated affiliates are named as defendants in litigation relating to our normal business activities, 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 activities. We are unaware of any significant litigation, pending or threatened, that could have a significant adverse effect on our consolidated financial position.

On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of other unitholders of TEPPCO, and derivatively on behalf of TEPPCO, concerning, among other things, certain transactions involving TEPPCO and Enterprise Products Partners or its affiliates. Mr. Brinkerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants (i) TEPPCO, its current and certain former directors, and certain of its affiliates; (ii) Enterprise Products Partners and certain of its affiliates; (iii) EPCO, Inc.; and (iv) Dan L. Duncan.

The amended complaint alleges, among other things, that the defendants have caused TEPPCO to enter into certain transactions with Enterprise Products Partners or its affiliates that were unfair to TEPPCO or otherwise unfairly favored Enterprise Products Partners or its affiliates over TEPPCO. These transactions are alleged to include the joint venture to further expand the Jonah Gathering System entered into by TEPPCO and one of Enterprise Products Partners’ affiliates in August 2006 and the sale by TEPPCO to one of Enterprise Products Partners’ affiliates of the Pioneer gas processing plant in March 2006. The amended complaint seeks (i) rescission of these transactions or an award of rescissory damages with respect thereto; (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the amended complaint; and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. We believe this lawsuit is without merit and intend to vigorously defend against it. See Note 15 for additional information regarding our relationship with TEPPCO.

On February 13, 2007, EPO received notice from the U.S. Department of Justice (“DOJ”) that it was the subject of a criminal investigation related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”). EPO is the operator of this pipeline. On February 14, 2007, EPO received a letter from the Environment and Natural Resources Division (“ENRD”) of the DOJ regarding this incident and a previous release of ammonia on September 27, 2004 from the same pipeline. The ENRD has indicated that it may pursue civil damages against EPO and Magellan as a result of these incidents. Based on this correspondence from the ENRD, the statutory maximum amount of civil fines that could be assessed against EPO and Magellan is up to $17.4 million in the aggregate. EPO is cooperating with the DOJ and is hopeful that an expeditious resolution of this civil matter acceptable to all parties will be reached in the near future. Magellan has agreed to indemnify EPO for the civil matter. On September 4,

2007, Enterprise Products Partners and the DOJ entered into a plea agreement whereby a wholly-owned subsidiary of EPO, Mapletree, LLC, pleaded guilty to a misdemeanor charge of negligence in connection with the releases and paid a fine of $1.0 million. The plea agreement concludes the DOJ's criminal investigation into the ammonia releases. At this time, we do not believe that a final resolution of the civil claims by the ENRD will have a material impact on our consolidated financial position.

On October 25, 2006, a rupture in the Magellan Ammonia Pipeline resulted in the release of ammonia near Clay Center, Kansas. The pipeline has been repaired and environmental remediation tasks related to this incident have been completed. At this time, we do not believe that this incident will have a material impact on our consolidated financial position.

Several lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing methyl tertiary butyl ether. In general, such suits have not named manufacturers of this product as defendants, and there have been no such lawsuits filed against our subsidiary that owns an octane-additive production facility. It is possible, however, that former manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2007. A description of each type of contractual obligation follows:

				Payment or Settlement due by Period
Contractual Obligations				Total	2008	2009	2010	2011	2012	Thereafter
Scheduled maturities of long-term debt				$ 6,896,500	$ --	$ 500,000	$ 591,840	$ 650,000	$ 697,160	$ 4,457,500
Operating lease obligations				$ 325,705	$ 27,785	$ 25,866	$ 23,306	$ 23,785	$ 23,137	$ 201,826
Purchase obligations:
	Product purchase commitments:
		Estimated payment obligations:
			Natural gas	$ 685,600	$ 137,345	$ 136,970	$ 136,970	$ 136,970	$ 137,345	$ --
			NGLs	$ 4,041,275	$ 697,277	$ 415,132	$ 415,132	$ 415,132	$ 415,132	$ 1,683,470
			Petrochemicals	$ 4,065,675	$ 1,751,152	$ 746,916	$ 514,155	$ 233,745	$ 141,623	$ 678,084
			Other	$ 60,385	$ 31,392	$ 14,962	$ 2,152	$ 2,051	$ 1,780	$ 8,048
		Underlying major volume commitments:
			Natural gas (in BBtus)	91,350	18,300	18,250	18,250	18,250	18,300	--
			NGLs (in MBbls)	50,798	9,745	5,086	5,086	5,086	5,086	20,709
			Petrochemicals (in MBbls)	45,207	20,115	8,100	5,604	2,541	1,556	7,291
	Service payment commitments			$ 8,962	$ 6,745	$ 1,564	$ 93	$ 93	$ 93	$ 374
	Capital expenditure commitments			$ 569,654	$ 569,654	$ --	$ --	$ --	$ --	$ --

Scheduled Maturities of Long-Term Debt. We have long-term and short-term payment obligations under debt agreements such as the indentures governing EPO’s senior notes and the credit agreement governing EPO’s Multi-Year Revolving Credit Facility. Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the periods indicated. See Note 12 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.

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, (iii) a railcar unloading terminal in Mont Belvieu, Texas and (iv) land held pursuant to right-of-way agreements. In general, our material lease agreements have original terms that range from 2 to 28 years and include renewal options that could extend the agreements for up to an additional 20 years.

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, 2007, 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 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, certain 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, 2007 applied to all future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. At December 31, 2007, we do not have any product purchase commitments with fixed or minimum pricing provisions with remaining terms in excess of one year.

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

We have short-term payment obligations relating to our capital projects and those of our unconsolidated affiliates. These commitments represent unconditional payment obligations to vendors for services rendered or products purchased. The preceding table presents our share of such commitments for the periods indicated.

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 4). This includes costs associated with unit option awards granted to these employees to purchase Enterprise Products Partners’ common units. At December 31, 2007, there were 2,315,000 unit options outstanding for which we were responsible for reimbursing EPCO for the costs of such awards.

The weighted-average strike price of unit option awards outstanding at December 31, 2007 was $26.18 per common unit. At December 31, 2007, 335,000 of these unit options were exercisable. An additional 285,000, 380,000, 510,000 and 805,000 of these unit options will be exercisable in 2008, 2009, 2010 and 2011, 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. See Note 4 for additional information regarding our accounting for equity awards.

Performance Guaranty

In December 2004, a subsidiary of ours entered into the Independence Hub Agreement (the “Agreement”) with six oil and natural gas producers. The Agreement, as amended, obligated our subsidiary to construct the Independence Hub offshore platform and to process 1 Bcf/d of natural gas and condensate for the producers. We guaranteed to the producers the construction-related performance of our subsidiary up to an amount of $340.8 million. The performance guaranty expired during the second quarter of 2007.

Other Claims

As part of our normal business activities with joint venture partners and certain customers and suppliers, we occasionally have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of December 31, 2007, claims against us totaled approximately $37.9 million. These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated. However, in our opinion, the likelihood of a material adverse outcome related to disputes against us is remote. Accordingly, accruals for loss contingencies related to these matters, if any, that might result from the resolution of such disputes have not been reflected in our consolidated financial statements.

Other Commitments

We transport and store natural gas, NGLs and petrochemicals for third parties under various processing, storage, transportation and similar agreements. These volumes are (i) accrued as product payables on our Consolidated Balance Sheet, (i) in transit for delivery to our customers or (iii) held at our storage facilities for redelivery to our customers. We are insured against any physical loss of such volumes due to catastrophic events. Under the terms of our natural gas, NGL and petrochemical storage agreements, we are generally required to redeliver volumes to the owner on demand. At December 31, 2007, NGL and petrochemical products aggregating 25.2 million barrels were due to be redelivered to their owners along with 16,223 BBtus of natural gas. See Note 2 for more information regarding accrued product payables.

Note 18.

Significant Risks and Uncertainties

Nature of Operations in Midstream Energy Industry

Our operations are within the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, certain petrochemicals and crude oil. As such, our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products, including changes in the relative price levels among these products. In general, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to 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 hydrocarbon products transported, gathered or processed at our facilities. A material decrease in natural gas or crude oil production or crude oil refining for reasons such as depressed commodity prices or a decrease in exploration and development activities, 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 using NGLs, (iii) increased competition from petroleum-based products due to pricing differences, (iv) adverse weather conditions, (v) government regulations affecting energy commodity prices, production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could adversely affect our results of operations, cash flows and 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. We generally do not require collateral for our financial instrument transactions.

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. EPCO attempts to place all insurance coverage with carriers having ratings of “A” or higher. However, two carriers associated with the EPCO insurance program were downgraded by Standard & Poor’s during 2006. One of these carriers is currently at “A-” and the other, “BBB.” At present, there is no indication that these two carriers would be unable to fulfill any insuring obligation. Furthermore, we currently do not have any claims which might be affected by these carriers. EPCO continues to monitor these situations.

We believe EPCO maintains adequate insurance coverage on our behalf; however, insurance will not cover every type of interruption that might occur. As a result of severe hurricanes such as Katrina and Rita that occurred in 2005, market conditions for obtaining property damage insurance coverage were difficult during 2006. Under EPCO’s renewed insurance programs, coverage was more restrictive, including increased physical damage and business interruption deductibles. For example, our deductible for onshore physical damage increased from $2.5 million to $5.0 million per event and our deductible period for onshore business interruption claims increased from 30 days to 60 days. Additional restrictions will be applied in connection with damage caused by named windstorms.

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 and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient to reimburse us for repair costs or lost income. Any event that 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 our common units.

The following is a discussion of the general status of our insurance claims related to recent significant storm events. 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 as additional information becomes available.

Hurricane Ivan insurance claims. During the year ended December 31, 2007 we received cash reimbursements from insurance carriers totaling $1.3 million related to property damage claims. If the final recovery of funds is different than the amount previously expended, we will recognize an income impact at that time.

We have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan, which struck the eastern U.S. Gulf Coast region in September 2004. During the year ended December 31, 2007 we received $0.4 million of nonrefundable cash proceeds from such claims. We are continuing our efforts to collect residual balances and expect to complete the process during 2008.

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. With respect to these storms, we have $37.6 million of estimated property damage claims outstanding at December 31, 2007, that we believe are probable of collection during the period 2008 through 2009. We continue to pursue collection of our property damage claims related to these named storms. As of December 31, 2007, we had received practically all proceeds from our business interruption claims related to these storm events.

The following table summarizes proceeds we received during the year ended December 31, 2007 from business interruption and property damage insurance claims with respect to certain named storms:

Business interruption proceeds:
	Hurricane Ivan	$ 377
	Hurricane Katrina	19,005
	Hurricane Rita	14,955
	Other	996
	Total proceeds	35,333
Property damage proceeds:
	Hurricane Ivan	1,273
	Hurricane Katrina	79,651
	Hurricane Rita	24,105
	Other	184
	Total proceeds	105,213
Total		$ 140,546

During 2007, we collected $0.8 million of business interruption proceeds that were not related to storm events.

Note 19. Condensed Financial Information of EPO

EPO conducts substantially all of our business. Currently, neither EPGP nor Enterprise Products Partners has any independent operations and any material assets outside those of EPO. EPO consolidates the financial statements of Duncan Energy Partners with those of its own.

Enterprise Products Partners guarantees the debt obligations of EPO, with the exception of the Dixie revolving credit facility and Duncan Energy Partners’ credit facility. If EPO were to default on any debt Enterprise Products Partners guarantees, Enterprise Products Partners would be responsible for full repayment of that obligation. See Note 12 for additional information regarding our consolidated debt obligations.

The reconciling items between our consolidated balance sheet and that of EPO are insignificant. The following table presents condensed consolidated balance sheet data for EPO at December 31, 2007:

ASSETS
Current assets		$ 2,544,973
Property, plant and equipment, net		11,587,264
Investments in and advances to unconsolidated affiliates, net		858,339
Intangible assets, net		917,000
Goodwill		591,652
Deferred tax asset		3,113
Other assets		112,345
	Total	$ 16,614,686
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities		$ 3,044,002
Long-term debt		6,906,145
Other long-term liabilities		95,112
Minority interest		439,854
Partners’ equity		6,129,573
	Total	$ 16,614,686

Total EPO debt obligations guaranteed by Enterprise Products Partners		$ 6,686,500

Note 20. Subsequent Event

Enterprise Products 2008 Long-Term Incentive Plan

On January 29, 2008, the unitholders of Enterprise Products Partners approved the Enterprise Products 2008 Long-Term Incentive Plan (the “Incentive Plan”), which provides for awards of the Enterprise Products Partners’ common units and other rights to the its non-employee directors and to consultants and employees of EPCO and its affiliates providing services to the Enterprise Products Partners. Awards under the Incentive Plan may be granted in the form of Enterprise Products Partners’ restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The Incentive Plan will be administered by EPGP’s ACG Committee. Up to 10,000,000 of Enterprise Products Partners’ common units may be granted as awards under the Incentive Plan, with such amount subject to adjustment as provided for under the terms of the plan.

The exercise price of unit options or UARs awarded to participants will be determined by the ACG Committee (at its discretion) at the date of grant and may be no less than the fair market value of the option award as of the date of grant. The Incentive Plan may be amended or terminated at any time by the Board of Directors of EPCO or EPGP’s ACG Committee; however, any material amendment, such as a significant increase in the number of units available under the plan or a change in the types of awards available under the plan, would require the approval of the unitholders of Enterprise Products Partners. The ACG Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the plan in specified circumstances. The Incentive Plan is effective until January 29, 2018 or, if earlier, the time which all available units under the Incentive Plan have been delivered to participants or the time of termination of the plan by EPCO or EPGP’s ACG Committee.

Enterprise Unit L.P. Long-Term Incentive Plan

On February 20, 2008, EPCO formed Enterprise Unit L.P. (“Enterprise LP”) to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in Enterprise LP. On that date, EPCO Holdings, Inc. (“EPCO Holdings”) agreed to contribute $18,000,000 in the aggregate (the “Initial Contribution”) to Enterprise LP and was admitted as the Class A limited partner. Certain key employees of EPCO including our Chief Executive Officer and Chief Financial Officer were issued Class B limited partner interests and admitted as Class B limited partners of Enterprise LP without any capital contribution. As with the awards granted in connection with the other Employee Partnerships, these awards

are designed to provide additional long-term incentive compensation for such employees. The profits interest awards (or Class B limited partner interests) in Enterprise LP entitle the holder to participate in the appreciation in value of Enterprise GP Holdings units and Enterprise Products Partners’ common units and are subject to forfeiture.

A portion of the fair value of these equity awards will be allocated to us under the EPCO administrative services agreement as a non-cash expense. We will not reimburse EPCO, Enterprise LP or any of their affiliates or partners, through the administrative services agreement or otherwise, for any expenses related to Enterprise LP, including the Initial Contribution by EPCO Holdings.

The Class B limited partner interests in Enterprise LP 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 February 20, 2014, with customary exceptions for death, disability and certain retirements. The risk of forfeiture associated with the Class B limited partner interests in Enterprise LP will also lapse upon certain change of control events.

Unless otherwise agreed to by EPCO, EPCO Holdings and a majority in interest of the Class B limited partners of Enterprise LP, Enterprise LP will terminate at the earlier of February 20, 2014 (six years from the date of the agreement) or a change in control of us or Enterprise GP Holdings. Enterprise LP has the following material terms regarding its quarterly cash distribution to partners:

Distributions of cash flow – Each quarter, 100% of the cash distributions received by Enterprise LP from Enterprise GP Holdings and Enterprise Products Partners will be distributed to the Class A limited partner until EPCO Holdings has received an amount equal to the Class A preferred return (as defined below), and any remaining distributions received by Enterprise LP will be distributed to the Class B limited partners. The Class A preferred return equals the Class A capital base (as defined below) multiplied by 5.0% per annum. The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to Enterprise LP, plus any unpaid Class A preferred return from prior periods, less any distributions made by Enterprise LP of proceeds from the sale of units owned by Enterprise LP (as described below).

Liquidating Distributions – Upon liquidation of Enterprise LP, units having a fair market value equal to the Class A limited partner capital base will be distributed to EPCO Holdings, 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 Enterprise LP sells any units that it beneficially owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above.