Enterprise Products Partners 8K Other Events | EPD 10 Aug 09

EXHIBIT 99.1

Enterprise Products GP, LLC

Unaudited Condensed Consolidated Balance Sheet at June 30, 2009

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ENTERPRISE PRODUCTS GP, LLC

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ENTERPRISE PRODUCTS GP, LLC

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

AT JUNE 30, 2009

(Dollars in millions)

ASSETS
Current assets:
Cash and cash equivalents	$	65.1
Restricted cash		184.4
Accounts and notes receivable – trade, net of allowance for doubtful accounts of $14.7		1,232.1
Accounts receivable – related parties		47.4
Inventories (see Note 5)		965.8
Derivative assets (see Note 4)		229.3
Prepaid and other current assets		144.9
Total current assets		2,869.0
Property, plant and equipment, net		13,582.0
Investments in unconsolidated affiliates		901.4
Intangible assets, net of accumulated amortization of $472.0		813.5
Goodwill		706.9
Deferred tax asset		1.1
Other assets		148.7
Total assets	$	19,022.6

LIABILITIES AND EQUITY
Current liabilities:
Current maturities of long-term debt	$	181.4
Accounts payable – trade		278.2
Accounts payable – related parties		96.0
Accrued product payables		1,526.2
Accrued interest payable		169.4
Other accrued expenses		32.3
Derivative liabilities (see Note 4)		337.0
Other current liabilities		191.1
Total current liabilities		2,811.6
Long-term debt: (see Note 9)
Senior debt obligations – principal		7,950.1
Junior subordinated notes – principal		1,232.7
Other		41.5
Total long-term debt		9,224.3
Deferred tax liabilities		68.8
Other long-term liabilities		99.0
Commitments and contingencies
Equity: (see Note 10)
Member’s interest		531.8
Accumulated other comprehensive loss		(2.7	)
Total member’s equity		529.1
Noncontrolling interest		6,289.8
Total equity		6,818.9
Total liabilities and equity	$	19,022.6

See Notes to Unaudited Condensed Consolidated Balance Sheet.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

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 millions of dollars.

Note 1. Company Organization

Company Organization

Enterprise Products GP, LLC is a Delaware limited liability company that was formed in April 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 June 30, 2009, 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”). 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 limited partnership, 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. On June 28, 2009, Enterprise Products Partners and TEPPCO (including TEPPCO GP) entered into definitive agreements to merge. See Note 12 for additional information regarding the merger agreements.

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. Enterprise GP Holdings owns noncontrolling interests in both LE GP and Energy Transfer Equity. Enterprise GP Holdings accounts for its investments in LE GP and Energy Transfer Equity using the equity method of accounting.

References to “Employee Partnerships” mean EPE Unit L.P., EPE Unit II, L.P., EPE Unit III, L.P., Enterprise Unit L.P. and EPCO Unit L.P., collectively, which are privately-held affiliates of EPCO, Inc.

References to “EPCO” mean EPCO, Inc. and its wholly-owned privately-held affiliates, which are related parties 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 L.P. (“Duncan Energy Partners”) with that of its own. Enterprise Products

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

Partners controls Duncan Energy Partners through the ownership of its general partner, DEP Holdings, LLC (“DEP GP”). Public ownership of Duncan Energy Partners’ net assets is presented as a component of noncontrolling interest in our Unaudited Condensed Consolidated Balance Sheet. The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, neither Enterprise Products Partners nor EPGP have 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 noncontrolling 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 capital account in Enterprise Products Partners.

Effective January 1, 2009, we adopted the provisions of Statement of Financial Accounting Standards (“SFAS”) 160 (Accounting Standards Codification (“ASC”) 810), Noncontrolling Interests in Consolidated Financial Statements – an amendment to ARB No. 51. SFAS 160 established accounting and reporting standards for noncontrolling interests, which were previously identified as minority interest in our Unaudited Condensed Consolidated Balance Sheet. This new standard requires, among other things, that noncontrolling interests be presented as a component of equity on our Unaudited Condensed Consolidated Balance Sheet (i.e., elimination of the “mezzanine” presentation previously used for minority interest).

The Consolidated Balance Sheet included in the Current Report on Form 8-K reflects the changes required by SFAS 160. This Unaudited Condensed Consolidated Balance Sheet and Notes thereto should be read in conjunction with the Audited Consolidated Balance Sheet and Notes thereto included in our Current Report on Form 8-K dated July 8, 2009 (the “Recast Form 8-K”), which retrospectively adjusted portions of our Current Report on Form 8-K for the year ended December 31, 2008 to reflect our adoption of SFAS 160.

Note 2. General Accounting Matters

Estimates

Preparing our Unaudited Condensed Consolidated Balance Sheet in conformity with generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect amounts presented in the balance sheet (e.g. assets and liabilities) and disclosures about contingent assets and liabilities. 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.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

Fair Value Information

Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, and other current liabilities 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. See Note 4 for fair value information associated with our derivative instruments. The following table presents the estimated fair values of our financial instruments at June 30:

	Carrying		Fair
Financial Instruments	Value		Value
Financial assets:
Cash and cash equivalents, including restricted cash	$	249.4	$	249.4
Accounts receivable		1,279.5		1,279.5
Financial liabilities:
Accounts payable and accrued expenses		2,102.1		2,102.1
Other current liabilities		191.1		191.1
Fixed-rate debt (principal amount)		7,986.7		7,760.9
Variable-rate debt		1,377.5		1,377.5

Recent Accounting Developments

The following information summarizes recently issued accounting guidance since those reported in our Recast Form 8-K that will or may affect our future financial statements.

In April 2009, the Financial Accounting Standards Board (“FASB”) issued new guidance in the form of FASB Staff Positions (“FSPs”) in an effort to clarify certain fair value accounting rules. FSP FAS 157-4 (ASC 820), Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, establishes a process to determine whether a market is not active and a transaction is not distressed. FSP FAS 157-4 states that companies should look at several factors and use judgment to ascertain if a formerly active market has become inactive. When estimating fair value, FSP FAS 157-4 requires companies to place more weight on observable transactions determined to be orderly and less weight on transactions for which there is insufficient information to determine whether the transaction is orderly (entities do not have to incur undue cost and effort in making this determination). The FASB also issued FSP FAS 107-1 and APB 28-1 (ASC 825), Interim Disclosures About Fair Value of Financial Instruments. This FSP requires that companies provide qualitative and quantitative information about fair value estimates for all financial instruments not measured on the balance sheet at fair value in each interim report. Previously, this was only an annual requirement. We adopted these FSPs on June 30, 2009. Our adoption of this new guidance did not have a material impact on our financial position or related disclosures.

In May 2009, the FASB issued SFAS 165 (ASC 855), Subsequent Events, which establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date. We adopted SFAS 165 on June 30, 2009. Our adoption of this guidance did not have any impact on our financial position.

In June 2009, the FASB issued SFAS 167 (ASC 810), Amendments to FASB Interpretation No. 46(R), which amended consolidation guidance for variable interest entities (“VIEs”) under FASB Interpretation (“FIN”) No. 46(R) (ASC 810-10), Consolidation of Variable Interest Entities. VIEs are entities whose equity investors do not have sufficient equity capital at risk such that the entity cannot finance its own activities. When a business has a controlling financial interest in a VIE, the assets, liabilities and profit or loss of that entity must be included in consolidation. A business enterprise must consolidate a VIE when that enterprise has a variable interest that will cover most of the entity’s expected losses and/or receive most of the entity’s anticipated residual return. SFAS 167, among other things,

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

eliminates the scope exception for qualifying special-purpose entities, amends certain guidance for determining whether an entity is a VIE, expands the list of events that trigger reconsideration of whether an entity is a VIE, requires a qualitative rather than a quantitative analysis to determine the primary beneficiary of a VIE, requires continuous assessments of whether a company is the primary beneficiary of a VIE and requires enhanced disclosures about a company’s involvement with a VIE. SFAS 167 is effective for us on January 1, 2010. At June 30, 2009, we did not have any VIEs; therefore, our adoption of this new guidance is not expected to have a material impact on our financial position.

In June 2009, the FASB also issued SFAS 168 (ASC 105), The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Statement No. 162, which establishes the ASC as the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. The ASC is a reorganization of current GAAP into a topical format that eliminates the current GAAP hierarchy and establishes two levels of guidance – authoritative and nonauthoritative. All guidance contained in the ASC carries an equal level of authority. Rules and interpretive releases of the SEC under federal securities laws are also sources of authoritative GAAP for SEC registrants. SFAS 168 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with GAAP. We will adopt SFAS 168 on September 30, 2009. Our adoption of this guidance is not expected to have any impact on our financial position. References to specific GAAP in our consolidated balance sheet after our adoption of SFAS 168 will refer exclusively to the ASC. We have elected to provide references to the ASC parenthetically in this Current Report.

Restricted Cash

Restricted cash represents amounts held in connection with our commodity derivative instruments portfolio and New York Mercantile Exchange (“NYMEX”) physical natural gas purchases. Additional cash may be restricted to maintain our positions as commodity prices fluctuate or deposit requirements change. At June 30, 2009, our restricted cash amounts were $184.4 million. See Note 4 for additional information regarding derivative instruments and hedging activities.

Subsequent Events

We have evaluated subsequent events through August 10, 2009, which is the date our Unaudited Condensed Consolidated Balance Sheet and Notes are being issued.

Note 3. Accounting for Equity Awards

We account for equity awards in accordance with SFAS 123(R) (ASC 505 and 718), Share-Based Payment. Such awards were not material to our consolidated financial position at June 30, 2009.

Certain key employees of EPCO participate in long-term incentive compensation plans managed by EPCO. We record our pro rata share of such costs based on the percentage of time each employee spends on our consolidated business activities.

EPCO 1998 Long-Term Incentive Plan

The EPCO 1998 Long-Term Incentive Plan (“EPCO 1998 Plan”) provides for the issuance of up to 7,000,000 of Enterprise Products Partners’ common units. After giving effect to the issuance or forfeiture of option awards and restricted unit awards through June 30, 2009, a total of 301,600 additional common units could be issued under the EPCO 1998 Plan.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

Unit option awards. The following table presents option activity under the EPCO 1998 Plan for the periods indicated:

						Weighted-
				Weighted-		Average
				Average		Remaining		Aggregate
	Number of			Strike Price		Contractual		Intrinsic
	Units			(dollars/unit)		Term (in years)		Value (1)
Outstanding at December 31, 2008		2,168,500		$	26.32
Granted (2)		30,000			20.08
Exercised		(25,000	)		13.16
Forfeited		(365,000	)		26.38
Outstanding at June 30, 2009		1,808,500			26.39		4.8	$	1.5
Options exercisable at
June 30, 2009		403,500			21.33		3.9	$	1.5

(1) Aggregate intrinsic value reflects fully vested unit options at June 30, 2009. (2) Aggregate grant date fair value of these unit options issued during 2009 was $0.2 million based on the following assumptions: (i) a grant date market price of Enterprise Products Partners’ common units of $20.08 per unit; (ii) expected life of options of 5.0 years; (iii) risk-free interest rate of 1.81%; (iv) expected distribution yield on Enterprise Products Partners’ common units of 10%; and (v) expected unit price volatility on Enterprise Products Partners’ common units of 72.76%.

The total intrinsic value of option awards exercised during the three months ended June 30, 2009 and 2008 was $0.2 million and $0.4 million, respectively. For the six months ended June 30, 2009 and 2008, the total intrinsic value of option awards exercised was $0.3 million and $0.5 million, respectively.

During the six months ended June 30, 2009 and 2008, we received cash of $0.2 million and $0.6 million, respectively, from the exercise of option awards granted under the EPCO 1998 Plan. Conversely, our option-related reimbursements to EPCO during each of these periods were $0.3 million and $0.5 million, respectively.

Restricted unit awards. The following table summarizes information regarding Enterprise Products Partners’ restricted unit awards under the EPCO 1998 Plan for the periods indicated:

				Weighted-
				Average Grant
	Number of			Date Fair Value
	Units			per Unit (1)
Restricted units at December 31, 2008		2,080,600
Granted (2)		1,011,350		$	20.63
Vested		(12,500	)		27.59
Forfeited		(144,000	)		29.41
Restricted units at June 30, 2009		2,935,450

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per unit for forfeited and vested awards is determined before an allowance for forfeitures. (2) Aggregate grant date fair value of restricted unit awards issued during 2009 was $20.9 million based on grant date market prices of Enterprise Products Partners’ common units ranging from $20.08 to $24.92 per unit and an estimated forfeiture rate ranging between 4.6% and 17%.

The total fair value of restricted unit awards that vested during the six months ended June 30, 2009 was $0.3 million. Such amount was immaterial for the three months ended June 30, 2009.

Phantom unit awards and distribution equivalent rights. No phantom unit awards or distribution equivalent rights have been issued as of June 30, 2009 under the EPCO 1998 Plan.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

Enterprise Products 2008 Long-Term Incentive Plan

The Enterprise Products 2008 Long-Term Incentive Plan (“EPD 2008 LTIP”) provides for the issuance of up to 10,000,000 of Enterprise Products Partners’ common units. After giving effect to the issuance or forfeiture of option awards through June 30, 2009, a total of 7,865,000 additional common units could be issued under the EPD 2008 LTIP.

Unit option awards. The following table presents unit option activity under the EPD 2008 LTIP for the periods indicated:

						Weighted-
				Weighted-		Average
				Average		Remaining
	Number of			Strike Price		Contractual
	Units			(dollars/unit)		Term (in years)
Outstanding at December 31, 2008		795,000		$	30.93
Granted (1)		1,430,000			23.53
Forfeited		(90,000	)		30.93
Outstanding at June 30, 2009 (2)		2,135,000			25.97		5.2

(1) Aggregate grant date fair value of these unit options issued during 2009 was $6.5 million based on the following assumptions: (i) a weighted-average grant date market price of Enterprise Products Partners’ common units of $23.53 per unit; (ii) weighted-average expected life of options of 4.9 years; (iii) weighted-average risk-free interest rate of 2.14%; (iv) expected weighted-average distribution yield on Enterprise Products Partners’ common units of 9.37%; (v) expected weighted-average unit price volatility on Enterprise Products Partners’ common units of 57.11%; and (vi) an estimated forfeiture rate of 17%. (2) No unit options were exercisable as of June 30, 2009.

Phantom unit awards. There were a total of 10,600 phantom units outstanding at June 30, 2009 under the EPD 2008 LTIP. These awards cliff vest in 2011 and 2012. At June 30, 2009 and December 31, 2008, we had accrued an immaterial liability for compensation related to these phantom unit awards.

DEP GP Unit Appreciation Rights

At June 30, 2009 and December 31, 2008, we had a total of 90,000 outstanding unit appreciation rights (“UARs”) 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. At June 30, 2009 and December 31, 2008, we had accrued an immaterial liability for compensation related to these UARs.

Note 4. Derivative Instruments and Hedging Activities

In the course of our normal business operations, we are exposed to certain risks, including changes in interest rates, commodity prices and, to a limited extent, foreign exchange rates. In order to manage risks associated with certain identifiable and anticipated transactions, we use derivative instruments. Derivatives are financial instruments whose fair value is determined by changes in a specified benchmark such as interest rates, commodity prices or currency values. Typical derivative instruments include futures, forward contracts, swaps and other instruments with similar characteristics. Substantially all of our derivatives are used for non-trading activities.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

SFAS 133 (ASC 815), Accounting for Derivative Instruments and Hedging Activities, requires companies to recognize derivative instruments at fair value as either assets or liabilities on the balance sheet. While the standard requires that all derivatives be reported at fair value on the balance sheet, changes in fair value of the derivative instruments will be reported in different ways depending on the nature and effectiveness of the hedging activities to which they are related. After meeting specified conditions, a qualified derivative may be specifically designated as a total or partial hedge of:

§	Changes in the fair value of a recognized asset or liability, or an unrecognized firm commitment,

§	Variable cash flows of a forecasted transaction,

§	Foreign currency exposure, such as through an unrecognized firm commitment.

An effective hedge is one in which the change in fair value of a derivative instrument can be expected to offset 80% to 125% of changes in the fair value of a hedged item at inception and throughout the life of the hedging relationship. The effective portion of a hedge is the amount by which the derivative instrument exactly offsets the change in fair value of the hedged item during the reporting period. Conversely, ineffectiveness represents the change in the fair value of the derivative instrument that does not exactly offset the change in the fair value of the hedged item. Ineffectiveness can be caused by, among other things, changes in the timing of forecasted transactions or a mismatch of terms between the derivative instrument and the hedged item.

On January 1, 2009, we adopted the disclosure requirements of SFAS 161 (ASC 815), Disclosures About Derivative Financial Instruments and Hedging Activities. SFAS 161 requires enhanced qualitative and quantitative disclosure requirements regarding derivative instruments. This footnote reflects the new disclosure standard.

Interest Rate Derivative Instruments

We utilize interest rate swaps, treasury locks and similar derivative instruments to manage our exposure to changes in the interest rates of certain consolidated debt agreements. This strategy is a component in controlling our cost of capital associated with such borrowings.

The following table summarizes our interest rate derivative instruments outstanding at June 30, 2009, all of which were designated as hedging instruments under SFAS 133:

	Number and Type of	Notional	Period of	Rate	Accounting
Hedged Transaction	Derivative Employed	Amount	Hedge	Swap	Treatment
Enterprise Products Partners:
Senior Notes C	1 fixed-to-floating swap	$100.0	1/04 to 2/13	6.4% to 3.5%	Fair value hedge
Senior Notes G	3 fixed-to-floating swaps	$300.0	10/04 to 10/14	5.6% to 2.6%	Fair value hedge
Senior Notes P	6 fixed-to-floating swaps	$350.0	6/09 to 8/12	4.6% to 2.8%	Fair value hedge
Duncan Energy Partners:
Variable-interest rate borrowings	3 floating-to-fixed swaps	$175.0	9/07 to 9/10	0.6% to 4.6%	Cash flow hedge

At times, we may use treasury lock derivative instruments to hedge the underlying U.S. treasury rates related to forecasted issuances of debt.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

In the first quarter of 2009, we entered into two forward starting interest rate swaps to hedge the underlying benchmark interest payments related to the forecasted issuances of debt.

	Number and Type of	Notional	Period of	Average Rate	Accounting
Hedged Transaction	Derivative Employed	Amount	Hedge	Locked	Treatment
Enterprise Products Partners:
Future debt offering	1 forward starting swap	$50.0	6/10 to 6/20	3.293%	Cash flow hedge
Future debt offering	1 forward starting swap	$150.0	2/11 to 2/21	3.4615%	Cash flow hedge

For information regarding consolidated fair value amounts on interest rate derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts on Derivative Instruments and Related Hedged Items” within this Note 4.

Commodity Derivative Instruments

The prices of natural gas, NGLs and certain petrochemical products are subject to fluctuations in response to changes in supply, demand, general market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risk associated with such products, we enter into commodity derivative instruments such as forwards, basis swaps and futures contracts. The following table summarizes our commodity derivative instruments outstanding at June 30, 2009:

	Volume (1)		Accounting
Derivative Purpose	Current	Long-Term (2)	Treatment
Derivatives designated as hedging instruments under SFAS 133:
Enterprise Products Partners:
Natural gas processing:
Forecasted natural gas purchases for plant thermal reduction (“PTR”) (3)	31.7 Bcf	n/a	Cash flow hedge
Forecasted NGL sales	2.2 MMBbls	n/a	Cash flow hedge
Octane enhancement:
Forecasted purchases of natural gas liquids	0.1 MMBbls	n/a	Cash flow hedge
Natural gas liquids inventory management activities	n/a	0.1 MMBbls	Cash flow hedge
Forecasted sales of octane enhancement products	1.5 MMBbls	n/a	Cash flow hedge
Natural gas marketing:
Natural gas storage inventory management activities	7.4 Bcf	n/a	Fair value hedge
NGL marketing:
Forecasted purchases of NGLs and related hydrocarbon products	2.3 MMBbls	n/a	Cash flow hedge
Forecasted sales of NGLs and related hydrocarbon products	5.0 MMBbls	0.8 MMBbls	Cash flow hedge

Derivatives not designated as hedging instruments under SFAS 133:
Enterprise Products Partners:
Natural gas risk management activities (4) (5)	296.1 Bcf	10.4 Bcf	Mark-to-market
Duncan Energy Partners:
Natural gas risk management activities (5)	1.6 Bcf	n/a	Mark-to-market
(1) Volume for derivatives designated as hedging instruments reflects the total amount of volumes hedged whereas volume for derivatives not designated as hedging instruments reflects the absolute value of derivative notional volumes. (2) The maximum term for derivatives included in the long-term column is December 2012. (3) PTR represents the British thermal unit (“Btu”) equivalent of the NGLs extracted from natural gas by a processing plant, and includes the natural gas used as plant fuel to extract those liquids, plant flare and other shortages. See the discussion below for the primary objective of this strategy. (4) Volume includes approximately 32.3 billion cubic feet (“Bcf”) of physical derivative instruments that are predominantly priced as an index plus a premium or minus a discount. (5) Reflects the use of derivative instruments to manage risks associated with natural gas transportation, processing and storage assets.

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

The table above does not include additional hedges of forecasted NGL sales executed under contracts that have been designated as normal purchase and sale agreements under SFAS 133. At June 30, 2009, the volume hedged under these contracts was 9.6 million barrels (“MMBbls”).

Certain of our derivative instruments do not meet the hedge accounting requirements of SFAS 133 and are accounted for as economic hedges using mark-to-market accounting.

Our predominant hedging strategy is a program to hedge a portion of our margin from natural gas processing. The objective of this strategy is to hedge a level of gross margins associated with the NGL forward sales contracts (i.e., NGL sales revenues less actual costs for PTR and the gain or loss on the PTR hedge) by locking in the cost of natural gas used for PTR through the use of commodity derivative instruments. This program consists of:

§	the forward sale of a portion of our expected equity NGL production at fixed prices through 2009, and

§	the purchase, using commodity derivative instruments, of the amount of natural gas expected to be consumed as PTR in the production of such equity NGL production.

At June 30, 2009, this program had hedged future estimated gross margins (before plant operating expenses) of $269.8 million on 10.4 MMBbls of forecasted NGL forward sales transactions extending through 2009.

For information regarding consolidated fair value amounts on commodity derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts on Derivative Instruments and Related Hedged Items” within this Note 4.

Foreign Currency Derivative Instruments

We are exposed to foreign currency exchange risk in connection with our NGL marketing activities in Canada. As a result, we could be adversely affected by fluctuations in currency rates between the U.S. dollar and Canadian dollar. In order to manage this risk, we may enter into foreign exchange purchase contracts to lock in the exchange rate. Prior to 2009, these derivative instruments were accounted for using mark-to-market accounting. Beginning with the first quarter of 2009, these transactions are accounted for as cash flow hedges.

In addition, we were exposed to foreign currency exchange risk in connection with a term loan denominated in Japanese yen (see Note 9). We entered into this loan agreement in November 2008 and the loan matured in March 2009. The derivative instrument used to hedge this risk was accounted for as a cash flow hedge and settled upon repayment of the loan.

We had one foreign currency derivative instrument with a notional amount of $1.7 million Canadian outstanding at June 30, 2009. The fair market value of this instrument was an asset of $0.1 million at June 30, 2009.

For information regarding consolidated fair value amounts on foreign currency derivative instruments and related hedged items, see “Tabular Presentation of Fair Value Amounts on Derivative Instruments and Related Hedged Items” within this Note 4.

Credit-Risk Related Contingent Features in Derivative Instruments

A limited number of our commodity derivative instruments include provisions related to credit ratings and/or adequate assurance clauses. A credit rating provision provides for a counterparty to demand immediate full or partial payment to cover a net liability position upon the loss of a stipulated credit rating. An adequate assurance clause provides for a counterparty to demand immediate full or partial payment to cover a net liability position should reasonable grounds for insecurity arise with respect to contractual

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

performance by either party. At June 30, 2009, the aggregate fair value of our over-the-counter derivative instruments in a net liability position was $8.0 million, of which approximately $7.8 million was subject to a credit rating contingent feature. If our credit ratings were downgraded to Ba2/BB, approximately $2.8 million would be payable as a margin deposit to the counterparties, and if our credit ratings were downgraded to Ba3/BB- or below, approximately $7.8 million would be payable as a margin deposit to the counterparties. The potential for derivatives with contingent features to enter a net liability position may change in the future as positions and prices fluctuate.

Tabular Presentation of Fair Value Amounts on

Derivative Instruments and Related Hedged Items

The following table provides a balance sheet overview of our derivative assets and liabilities at June 30, 2009:

	Asset Derivatives			Liability Derivatives
	Balance Sheet	Fair		Balance Sheet	Fair
	Location	Value		Location	Value

Derivatives designated as hedging instruments under SFAS 133
Interest rate derivatives	Derivative assets	$	18.7	Derivative liabilities	$	5.3
Interest rate derivatives	Other assets		32.3	Other liabilities		4.7
Total interest rate derivatives			51.0			10.0

Commodity derivatives	Derivative assets		101.8	Derivative liabilities		228.3
Commodity derivatives	Other assets		0.1	Other liabilities		3.7
Total commodity derivatives (1)			101.9			232.0

Foreign current derivatives (2)	Derivative assets		0.1			--
Total derivatives designated as hedging instruments		$	153.0		$	242.0

Derivatives not designated as hedging instruments under SFAS 133
Commodity derivatives	Derivative assets	$	108.7	Derivative liabilities	$	103.4
Commodity derivatives	Other assets		0.2	Other liabilities		0.1
Total commodity derivatives			108.9			103.5

Total derivatives not designated as hedging instruments		$	108.9		$	103.5

(1) Represent commodity derivative 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 foreign currency exchange rate related to our Canadian NGL marketing subsidiary.

SFAS 157 – Fair Value Measurements

SFAS 157 (ASC 820) defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

SFAS 157 established a three-tier hierarchy that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet

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reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the SFAS 157 hierarchy are described as follows:

Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur with sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the NYMEX). Our Level 1 fair values primarily consist of financial assets and liabilities such as exchange-traded commodity financial instruments.

Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, the time value of money, volatility factors, current market and contractual prices for the underlying instruments and other relevant economic measures. Substantially all of these assumptions are (i) observable in the marketplace throughout the full term of the instrument, (ii) can be derived from observable data or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Our Level 2 fair values primarily consist of commodity financial instruments such as forwards, swaps and other instruments transacted on an exchange or over the counter. The fair values of these derivatives are based on observable price quotes for similar products and locations. The value of our interest rate derivatives are valued by using appropriate financial models with the implied forward LIBOR yield curve for the same period as the future interest swap settlements.

Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. Our Level 3 fair values largely consist of ethane and normal butane-based contracts with a range of two to twelve months in term. We rely on broker quotes for these products due to the forward markets for these products being less liquid.

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The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at June 30, 2009. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Level 1		Level 2		Level 3		Total
Financial assets:
Interest rate derivative instruments	$	--	$	51.0	$	--	$	51.0
Commodity derivative instruments		12.7		179.0		19.1		210.8
Foreign currency derivatives		--		0.1		--		0.1
Total	$	12.7	$	230.1	$	19.1	$	261.9

Financial liabilities:
Interest rate derivative instruments	$	--	$	10.0	$	--	$	10.0
Commodity derivative instruments		58.2		269.0		8.3		335.5
Total	$	58.2	$	279.0	$	8.3	$	345.5

The following table sets forth a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities since December 31, 2008:

Balance, January 1	$	32.6		$	(4.6	)
Total gains (losses) included in:
Net income		12.5			(2.3	)
Other comprehensive income (loss)		1.5			2.4
Purchases, issuances, settlements		(12.5	)		1.9
Balance, March 31		34.1			(2.6	)
Total gains (losses) included in:
Net income		7.7			0.3
Other comprehensive income (loss)		(23.1	)		(2.4	)
Purchases, issuances, settlements		(7.7	)		0.1
Transfers out of Level 3		(0.2	)		--
Balance, June 30	$	10.8		$	(4.6	)

We adopted the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009. Our adoption of this guidance had no impact on our financial position. Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis and subject to fair value adjustments in certain circumstances (for example, when there is evidence of impairment). There were no fair value adjustments for such assets or liabilities reflected in our consolidated financial statements for the three and six months ended June 30, 2009.

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Note 5. Inventories

Our inventory amounts were as follows at June 30, 2009:

Working inventory (1)	$	438.8
Forward sales inventory (2)		527.0
Total inventory	$	965.8

(1) Working inventory is comprised of inventories of natural gas, NGLs and certain petrochemical products that are either available-for-sale or used in providing services. (2) Forward sales inventory consists of identified NGL and natural gas volumes dedicated to the fulfillment of forward sales contracts. As a result of energy market conditions, we significantly increased our physical inventory purchases and related forward physical sales commitments during 2009. Of the $527.0 million in forward sales inventory at June 30, 2009, approximately $432.0 million relates to forward sales NGL volumes. In general, the significant increase in volumes dedicated to forward physical sales contracts improves the overall utilization and profitability of our fee-based assets. The cash invested in forward sales NGL inventories is expected to be recovered within the next twelve months, with approximately $163.4 million realized by December 31, 2009.

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.

Due to fluctuating commodity prices, we recognize lower of average cost or market (“LCM”) adjustments when the carrying value of our available-for-sale inventories exceed their net realizable value.

Note 6. Property, Plant and Equipment

Our property, plant and equipment values and accumulated depreciation balances were as follows at June 30, 2009:

	Estimated
	Useful Life
	in Years
Plants and pipelines (1)		3-45 (5)	$	13,863.8
Underground and other storage facilities (2)		5-35 (6)		930.8
Platforms and facilities (3)		20-31		637.5
Transportation equipment (4)		3-10		39.3
Land				59.0
Construction in progress				669.8
Total				16,200.2
Less accumulated depreciation				2,618.2
Property, plant and equipment, net			$	13,582.0

(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, 18-45 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).

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In May 2009, we acquired certain rail and truck terminal facilities located in Mont Belvieu, Texas from Martin Midstream Partners L.P. (“Martin”). Cash consideration paid for this business combination was $23.7 million, all of which was recorded as additions to property, plant and equipment.

Asset Retirement Obligations

Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of certain tangible long-lived assets that result from acquisitions, construction, development and/or normal operations. The following table presents information regarding our AROs since December 31, 2008.

ARO liability balance, December 31, 2008	$	37.7
Liabilities incurred		0.4
Liabilities settled		(11.1	)
Revisions in estimated cash flows		21.3
Accretion expense		1.1
ARO liability balance, June 30, 2009	$	49.4

The increase in our ARO liability balance during 2009 primarily reflects revised estimates of the cost to comply with regulatory abandonment obligations associated with our facilities offshore in the Gulf of Mexico. We incurred $11.1 million of costs through June 30, 2009 as a result of ARO settlement activities associated with certain pipeline laterals and a platform located in the Gulf of Mexico.

Property, plant and equipment at June 30, 2009 includes $24.9 million of asset retirement costs capitalized as an increase in the associated long-lived asset.

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Note 7. Investments in Unconsolidated Affiliates

We own interests in a number of related businesses that are accounted for using the equity method of accounting. Our investments in unconsolidated affiliates are grouped according to the business segment to which they relate. See Note 11 for a general discussion of our business segments. The following table shows our investments in unconsolidated affiliates at June 30:

	Ownership
	Percentage at
	June 30,
	2009
NGL Pipelines & Services:
Venice Energy Service Company, L.L.C.		13.1%	$	31.6
K/D/S Promix, L.L.C. (“Promix”)		50%		47.8
Baton Rouge Fractionators LLC		32.2%		23.3
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”)		49%		37.0
Onshore Natural Gas Pipelines & Services:
Jonah Gas Gathering Company (“Jonah”)		19.4%		250.4
Evangeline (1)		49.5%		5.0
White River Hub, LLC		50%		27.2
Offshore Pipelines & Services:
Poseidon Oil Pipeline, L.L.C. (“Poseidon”)		36%		59.8
Cameron Highway Oil Pipeline Company (“Cameron Highway”)		50%		246.7
Deepwater Gateway, L.L.C.		50%		102.9
Neptune Pipeline Company, L.L.C. (“Neptune”)		25.7%		54.5
Nemo Gathering Company, LLC		33.9%		--
Texas Offshore Port System (“TOPS”) (2)		--		--
Petrochemical Services:
Baton Rouge Propylene Concentrator, LLC		30%		11.7
La Porte (3)		50%		3.5
Total			$	901.4

(1) Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively. (2) In April 2009, we elected to dissociate from this partnership and forfeit our investment (see discussion below). (3) Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

Our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway, Jonah and Skelly-Belvieu include excess cost amounts totaling $55.4 million at June 30, 2009, all of which are 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.

In August 2008, a wholly owned subsidiary of Enterprise Products Partners, together with a subsidiary of TEPPCO and Oiltanking Holding Americas, Inc. (“Oiltanking”), formed the TOPS partnership. Effective April 16, 2009, Enterprise Products Partners’ wholly owned subsidiary dissociated from TOPS. We believe that the dissociation discharged Enterprise Products Parnters’ affiliate with respect to further obligations under the TOPS partnership agreement, and accordingly, Enterprise Products Partners from the associated liability under the related parent guarantee; therefore, we have not recorded any amounts related to such guarantee. The wholly owned subsidiary of TEPPCO that was a partner in TOPS also dissociated from the partnership effective April 16, 2009. See Note 14 for litigation matters associated with our dissociation from TOPS.

On a quarterly basis, we monitor the underlying business fundamentals of our investments in unconsolidated affiliates and test such investments for impairment when impairment indicators are present. As a result of our reviews for the second quarter of 2009, no impairment charges were required. We have the intent and ability to hold these investments, which are integral to our operations.

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Note 8. Intangible Assets and Goodwill

Identifiable Intangible Assets

The following table summarizes our intangible assets by segment at June 30, 2009:

	Gross		Accum.			Carrying
	Value		Amort.			Value
NGL Pipelines & Services:
Customer relationship intangibles	$	237.4	$	(77.9	)	$	159.5
Contract-based intangibles		299.9		(126.8	)		173.1
Subtotal		537.3		(204.7	)		332.6
Onshore Natural Gas Pipelines & Services:
Customer relationship intangibles		372.0		(113.9	)		258.1
Contract-based intangibles		101.3		(40.9	)		60.4
Subtotal		473.3		(154.8	)		318.5
Offshore Pipelines & Services:
Customer relationship intangibles		205.8		(98.2	)		107.6
Contract-based intangibles		1.2		(0.2	)		1.0
Subtotal		207.0		(98.4	)		108.6
Petrochemical Services:
Customer relationship intangibles		53.0		(11.2	)		41.8
Contract-based intangibles		14.9		(2.9	)		12.0
Subtotal		67.9		(14.1	)		53.8
Total	$	1,285.5	$	(472.0	)	$	813.5

Goodwill

The following table summarizes our goodwill amounts by business segment at June 30, 2009:

NGL Pipelines & Services	$	269.0
Onshore Natural Gas Pipelines & Services		282.1
Offshore Pipelines & Services		82.1
Petrochemical Services		73.7
Total	$	706.9

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Note 9. Debt Obligations

Our consolidated debt obligations consisted of the following at June 30, 2009:

EPO senior debt obligations:
Multi-Year Revolving Credit Facility, variable rate, due November 2012	$	853.2
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010 (1)		54.0
Petal GO Zone Bonds, variable rate, due August 2037		57.5
Senior Notes B, 7.50% fixed-rate, due February 2011		450.0
Senior Notes C, 6.375% fixed-rate, due February 2013		350.0
Senior Notes D, 6.875% fixed-rate, due March 2033		500.0
Senior Notes F, 4.625% fixed-rate, due October 2009 (1)		500.0
Senior Notes G, 5.60% fixed-rate, due October 2014		650.0
Senior Notes H, 6.65% fixed-rate, due October 2034		350.0
Senior Notes I, 5.00% fixed-rate, due March 2015		250.0
Senior Notes J, 5.75% fixed-rate, due March 2035		250.0
Senior Notes K, 4.950% fixed-rate, due June 2010 (1)		500.0
Senior Notes L, 6.30% fixed-rate, due September 2017		800.0
Senior Notes M, 5.65% fixed-rate, due April 2013		400.0
Senior Notes N, 6.50% fixed-rate, due January 2019		700.0
Senior Notes O, 9.75% fixed-rate, due January 2014		500.0
Senior Notes P, 4.60% fixed-rate, due August 2012		500.0
Duncan Energy Partners’ debt obligations:
DEP Revolving Credit Facility, variable rate, due February 2011		184.5
DEP Term Loan, variable rate, due December 2011		282.3
Total principal amount of senior debt obligations		8,131.5
EPO Junior Subordinated Notes A, fixed/variable rate, due August 2066		550.0
EPO Junior Subordinated Notes B, fixed/variable rate, due January 2068		682.7
Total principal amount of senior and junior debt obligations		9,364.2
Other, non-principal amounts:
Change in fair value of debt-related derivative instruments		34.1
Unamortized discounts, net of premiums		(7.3	)
Unamortized deferred net gains related to terminated interest rate swaps		14.7
Total other, non-principal amounts		41.5
Total debt obligations		9,405.7
Less current maturities of debt		(181.4	)
Total long-term debt	$	9,224.3

Letters of credit outstanding	$	111.7

(1) In accordance with SFAS 6 (ASC 470), Classification of Short-Term Obligations Expected to be Refinanced, long-term and current maturities of debt reflect the classification of such obligations at June 30, 2009 after taking into consideration EPO’s ability to use available borrowing capacity under its Multi-Year Revolving Credit Facility.

Parent-Subsidiary Guarantor Relationships

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO with the exception of the DEP Revolving Credit Facility and the DEP Term Loan. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full repayment of that obligation.

Letters of Credit

At June 30, 2009, EPO had outstanding a $60.0 million letter of credit relating to its commodity derivative instruments and a $50.7 million letter of credit related to its Petal GO Zone Bonds. These letter of credit facilities do not reduce the amount available for borrowing under EPO’s credit facilities. In addition, Duncan Energy Partners had an outstanding letter of credit in the amount of $1.0 million at June 30, 2009, which does reduce the amount available for borrowing under its credit facility.

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EPO’s Debt Obligations

Apart from that discussed below, there have been no significant changes in the terms of our debt obligations since those reported in our Recast Form 8-K.

$200.0 Million Term Loan. In April 2009, EPO entered into a $200.0 Million Term Loan, which was subsequently repaid and terminated in June 2009 using funds from the issuance of Senior Notes P.

364-Day Revolving Credit Facility. In November 2008, EPO executed a standby 364-Day Revolving Credit Agreement (the “364-Day Facility”) that had a borrowing capacity of $375.0 million. The 364-Day Facility was terminated in June 2009 under its terms as a result of the issuance of Senior Notes P. No amounts were borrowed under this standby facility through its termination date.

Senior Notes P. In June 2009, EPO sold $500.0 million in principal amount of 3-year senior unsecured notes (“Senior Notes P”). Senior Notes P were issued at 99.95% of their principal amount, have a fixed interest rate of 4.60% and mature on August 1, 2012. Net proceeds from the issuance of Senior Notes P were used (i) to repay amounts borrowed under the $200 Million Term Loan, (ii) to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and (iii) for general partnership purposes.

Senior Notes P rank equal with EPO’s existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. Senior Notes P 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.

Dixie Revolving Credit Facility

The Dixie Revolving Credit Facility was terminated in January 2009.

Covenants

We were in compliance with the covenants of our consolidated debt agreements at June 30, 2009.

Information Regarding Variable Interest Rates Paid

The following table shows the weighted-average interest rate paid on our consolidated variable-rate debt obligations during the six months ended June 30, 2009.

	Weighted-Average
	Interest Rate
	Paid
EPO’s Multi-Year Revolving Credit Facility	1.03%
DEP Revolving Credit Facility	1.89%
DEP Term Loan	1.31%
Petal GO Zone Bonds	0.91%

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Consolidated Debt Maturity Table

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

2009 (1)	$	500.0
2010 (1)		554.0
2011		916.8
2012		1,353.2
2013		750.0
Thereafter		5,290.2
Total scheduled principal payments	$	9,364.2

(1) Long-term and current maturities of debt reflect the classification of such obligations on our Unaudited Condensed Consolidated Balance Sheet at June 30, 2009 after taking into consideration EPO’s ability to use available borrowing capacity under its Multi-Year Revolving Credit Facility.

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 June 30, 2009, (ii) total debt of each unconsolidated affiliate at June 30, 2009 (on a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities of such debt.

	Our				Scheduled Maturities of Debt
	Ownership
	Interest		Total		2009		2010		2011
Poseidon		36%	$	90.0	$	--	$	--	$	90.0
Evangeline		49.5%		15.7		5.0		3.2		7.5
Total			$	105.7	$	5.0	$	3.2	$	97.5

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 June 30, 2009. The credit agreements of our unconsolidated affiliates also 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.

There have been no significant changes in the terms of the debt obligations of our unconsolidated affiliates since those reported in our Recast Form 8-K.

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Note 10. Equity

At June 30, 2009, equity consisted of the capital account of Enterprise GP Holdings, accumulated other comprehensive loss and noncontrolling interest.

Accumulated Other Comprehensive Loss

The following table summarizes transactions affecting our accumulated other comprehensive loss.

	Accumulated
	Other
	Comprehensive
	Loss
	Balance
Balance, December 31, 2008	$	(2.0	)
Net commodity financial instrument losses during period		(0.8	)
Net interest rate financial instrument gains during period		0.1
Balance, June 30, 2009	$	(2.7	)

Noncontrolling Interest

The following table shows the components of noncontrolling interest at June 30, 2009:

Limited partners of Enterprise Products Partners:
Third-party owners of Enterprise Products Partners (1)	$	5,188.9
Related party owners of Enterprise Products Partners (2)		718.8
Limited partners of Duncan Energy Partners:
Third-party owners of Duncan Energy Partners (3)		402.6
Joint venture partners (4)		111.5
Accumulated other comprehensive loss attributable to
noncontrolling interest		(132.0	)
Total noncontrolling interest on Consolidated Balance Sheet	$	6,289.8

(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. (4) Represents third-party ownership interests in joint ventures that we consolidate, including Seminole Pipeline Company, Tri-States Pipeline, L.L.C., Independence Hub, LLC and Wilprise Pipeline Company, L.L.C.

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Note 11. 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.

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 June 30, 2009	$	6,054.7	$	4,613.2	$	1,523.2	$	721.1	$	669.8	$	13,582.0
Investments in unconsolidated affiliates: (see Note 7)
At June 30, 2009		139.7		282.6		463.9		15.2		--		901.4
Intangible assets, net: (see Note 8)
At June 30, 2009		332.6		318.5		108.6		53.8		--		813.5
Goodwill: (see Note 8)
At June 30, 2009		269.0		282.1		82.1		73.7		--		706.9

Note 12. Related Party Transactions

The following table summarizes our related party receivable and payable amounts at June 30, 2009:

Accounts receivable - related parties:
EPCO and affiliates	$	36.9
Energy Transfer Equity and subsidiaries		5.4
Unconsolidated affiliates		5.1
Total	$	47.4

Accounts payable - related parties:
EPCO and affiliates	$	63.3
Energy Transfer Equity and subsidiaries		28.9
Unconsolidated affiliates		3.8
Total	$	96.0

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.

Significant Relationships and Agreements 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 privately-held affiliates;

§	Enterprise GP Holdings, which owns and controls EPGP;

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§	TEPPCO and its general partner, which are owned and/or controlled by Enterprise GP Holdings; and

§	the Employee Partnerships.

We also have an ongoing relationship with Duncan Energy Partners, the financial statements of which are consolidated with our own financial statements. Our transactions with Duncan Energy Partners are eliminated in consolidation. A description of our relationship with Duncan Energy Partners is presented within this Note 12.

EPCO is a privately-held company controlled by Dan L. Duncan, who is also a director and Chairman of EPGP. At June 30, 2009, EPCO and its affiliates beneficially owned 158,930,186 (or 34.5%) of Enterprise Products Partners’ outstanding common units, which includes 13,670,925 of Enterprise Products Partners’ common units owned by Enterprise GP Holdings. In addition, at June 30, 2009, EPCO and its affiliates beneficially owned 77.8% 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 our 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 $81.7 million and $69.7 million from Enterprise Products Partners during the six months ended June 30, 2009 and 2008, respectively. These amounts include incentive distributions of $71.8 million and $60.8 million for the six months ended June 30, 2009 and 2008, respectively.

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 privately-held subsidiaries 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 privately-held affiliates received from Enterprise Products Partners and Enterprise GP Holdings $230.3 million and $197.5 million in cash distributions during the six months ended June 30, 2009 and 2008, respectively.

EPCO ASA. We have no employees. Substantially all of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to the ASA. Enterprise Products Partners, Duncan Energy Partners, Enterprise GP Holdings, TEPPCO and their respective general partners are among the parties to the ASA.

Relationship with TEPPCO

TEPPCO became a related party to us in February 2005 when its general partner was acquired by privately-held affiliates of EPCO. Our relationship was further reinforced by the acquisition of TEPPCO’s general partner by Enterprise GP Holdings in May 2007. Enterprise GP Holdings also owns EPGP.

In August 2006, we became joint venture partners with TEPPCO in Jonah. We own an approximate 19.4% interest in Jonah and TEPPCO owns the remaining 80.6% interest. Our investment in Jonah at June 30, 2009 was $250.4 million.

In August 2008, we, together with TEPPCO and Oiltanking, announced the formation of TOPS. On April 16, 2009, we, along with TEPPCO, dissociated ourselves from TOPS (see Note 7).

Proposed Merger of TEPPCO and TEPPCO GP with Enterprise Products Partners. On June 28, 2009, we, Enterprise Products Partners and two of its subsidiaries entered into definitive merger agreements with TEPPCO and TEPPCO GP. Under the terms of the definitive agreements, TEPPCO and TEPPCO GP would become Enterprise Products Partners' wholly owned subsidiaries and each of TEPPCO’s unitholders, except for a certain privately-held affiliate of EPCO, would receive 1.24 of

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Enterprise Products Partners’ common units for each TEPPCO unit. A privately-held affiliate of EPCO would exchange its 11,486,711 TEPPCO units for 14,243,521 of Enterprise Products Partners' limited partner units, based on the 1.24 exchange rate, consisting of 9,723,090 of Enterprise Products Partners’ common units and 4,520,431 of Enterprise Products Partners’ Class B units. The Class B units will not be entitled to regular quarterly cash distributions for sixteen quarters following the closing of the merger. The Class B units would convert automatically into the same number of common units on the date immediately following the payment date for the sixteenth quarterly distribution following the closing of the merger. The Class B units will be entitled to vote together with the common units as a single class on partnership matters and, except for the payment of distributions, will have the same rights and privileges as Enterprise Products Partners' common units. No fractional common units would be issued in the proposed merger, and TEPPCO unitholders would, instead, receive cash in lieu of fractional common units, if any.

Under the terms of the definitive agreements, Enterprise GP Holdings would receive 1,331,681 of Enterprise Products Partners' common units and an increase in our capital account to maintain its 2% general partner interest in Enterprise Products Partners as consideration for 100% of the membership interests of TEPPCO GP. The respective ACG Committees of us and Enterprise GP Holdings each voted unanimously to approve the merger and a Special Committee of the ACG Committee of TEPPCO GP voted unanimously to recommend the merger.

Following the closing of the proposed merger, we expect affiliates of EPCO would own approximately 29.5% of Enterprise Products Partners outstanding limited partner units, including 3.4% owned by Enterprise GP Holdings.

Completion of the proposed merger is subject to the approval of holders of at least a majority of the outstanding TEPPCO units. In addition, pursuant to the merger agreement providing for the merger of TEPPCO, the number of votes cast in favor of the merger agreement by TEPPCO’s unitholders (excluding specified unitholders affiliated with EPCO and other specified officers and directors of TEPPCO GP, Enterprise GP Holdings and us) must exceed the number of votes actually cast against the merger agreement by such unaffiliated TEPPCO unitholders. Affiliates of EPCO, including Enterprise GP Holdings, have executed a support agreement in which they have agreed to vote their units in favor of the merger agreement and in which Enterprise GP Holdings acknowledges and agrees that it has executed a written consent as the sole member of TEPPCO GP approving the merger agreement to merge TEPPCO GP with us. The closing is also subject to customary regulatory approvals, including those under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended. Subject to the receipt of regulatory and TEPPCO unitholder approvals, completion of the proposed merger is expected to occur during the fourth quarter of 2009. See Note 13 for information regarding litigation matters associated with the proposed merger.

The merger agreement providing for the merger of TEPPCO contains provisions granting both TEPPCO and Enterprise Products Partners the right to terminate the agreement for certain reasons, including, among others, (i) if TEPPCO’s merger into Enterprise Products Partners’ subsidiary has not occurred on or before December 31, 2009 and (ii) TEPPCO’s failure to obtain unitholder approval as described above.

Loan Agreement with TEPPCO. On August 5, 2009, EPO entered into a Loan Agreement (the “Loan Agreement”) with TEPPCO under which EPO agreed to make an unsecured revolving loan to TEPPCO in an aggregate maximum outstanding principal amount not to exceed $100.0 million. See Note 15 for additional information regarding this Loan Agreement.

Relationship with Energy Transfer Equity

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

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We have a long-term revenue generating contract with Titan Energy Partners, L.P. (“Titan”), a consolidated subsidiary of 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.

Relationship with Duncan Energy Partners

Duncan Energy Partners was formed in September 2006 and did not acquire any assets prior to February 5, 2007, which was the date it completed its initial public offering and acquired controlling interests in five midstream energy businesses from EPO in a dropdown transaction (the “DEP I Midstream Businesses”). On December 8, 2008, through a second dropdown transaction, Duncan Energy Partners acquired controlling interests in three additional midstream energy businesses from EPO (the “DEP II Midstream Businesses”). The business purpose of Duncan Energy Partners is to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO and other affiliates under common control. Duncan Energy Partners is engaged in the business of transporting and storing NGLs and petrochemical products and gathering, transporting, storing and marketing of natural gas.

At June 30, 2009, Duncan Energy Partners was owned 99.3% by its limited partners and 0.7% by its general partner, DEP GP, which is a wholly owned subsidiary of EPO. DEP GP is responsible for managing the business and operations of Duncan Energy Partners. DEP Operating Partnership, L.P., a wholly owned subsidiary of Duncan Energy Partners, conducts substantially all of Duncan Energy Partners’ business. At June 30, 2009, EPO beneficially owned approximately 61% of Duncan Energy Partners’ limited partner interests and 100% of its general partner.

Enterprise Products Partners has continued involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions: (i) it utilizes Duncan Energy Partners’ storage services to support its Mont Belvieu fractionation and other businesses; (ii) it buys from, and sells to, Duncan Energy Partners natural gas in connection with its normal business activities; and (iii) it is currently the sole shipper on an NGL pipeline system located in south Texas that is owned by Duncan Energy Partners.

Duncan Energy Partners issued an aggregate 8.9 million of its common units in June and July 2009, which generated net proceeds of approximately $137.7 million ($123.2 million of which had been received as of June 30, 2009). Duncan Energy Partners used the net proceeds from its issuance of these units to repurchase and cancel an equal number of its common units beneficially owned by EPO. The repurchase of Duncan Energy Partners’ common units beneficially owned by EPO was reviewed and approved by the ACG Committees of EPGP and DEP GP. At August 1, 2009, EPO beneficially owned approximately 58% of Duncan Energy Partners’ limited partner interests and 100% of its general partner.

Omnibus Agreement. 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 construction costs above the (i) $28.6 million of estimated capital expenditures to complete Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated construction costs for additional brine production capacity and above-ground storage reservoir projects at Mont Belvieu, Texas. Both projects were underway at the time of Duncan Energy Partners’ initial public offering. EPO made cash contributions to Duncan Energy Partners of $1.4 million and $36.7 million in connection with the Omnibus Agreement during the six months ended June 30, 2009 and 2008, respectively. The majority of these contributions related to funding the Phase II expansion costs of the DEP South Texas NGL Pipeline System. EPO will not receive an increased allocation of earnings or cash flows as a result of these contributions to South Texas NGL and Mont Belvieu Caverns.

Mont Belvieu Caverns’ LLC Agreement. EPO made cash contributions of $12.7 million and $68.1 million under the Mont Belvieu Caverns limited liability company agreement during the six months ended June 30, 2009 and 2008, respectively, to fund 100% of certain storage-related projects for the benefit of EPO’s NGL marketing activities. At present, Mont Belvieu Caverns is not expected to generate any

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identifiable incremental cash flows in connection with these projects; thus, the sharing ratio for Mont Belvieu Caverns is not expected to change from the current sharing ratio of 66% for Duncan Energy Partners and 34% for EPO. EPO expects to make additional contributions of approximately $22.4 million to fund such projects in 2009. The constructed assets will be the property of Mont Belvieu Caverns.

Company and Limited Partnership Agreements – DEP II Midstream Businesses. Enterprise Holdings III, LLC (“Enterprise III”) has not yet participated in expansion project spending with respect to the DEP II Midstream Businesses, although it may elect to invest in existing or future expansion projects at a later date. As a result, Enterprise GTM Holdings L.P. has funded 100% of such growth capital spending and its Distribution Base has increased from $473.4 million at December 31, 2008 to $665.4 million at June 30, 2009. The Enterprise III Distribution Base was unchanged at $730.0 million at June 30, 2009.

Relationships with Unconsolidated Affiliates

Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline and Promix. In addition, we purchase NGL storage, transportation and fractionation services from Promix and natural gas from Jonah. For additional information regarding our unconsolidated affiliates, see Note 7.

Note 13. Commitments and Contingencies

Litigation

On occasion, we or our unconsolidated affiliates are named as a defendant in litigation and legal proceedings, including regulatory and environmental matters. Although we are insured against various 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. We are unaware of any litigation, pending or threatened, that we believe is reasonably likely to have a significant adverse effect on our financial position.

We evaluate our ongoing litigation based upon a combination of litigation and settlement alternatives. These reviews are updated as the facts and combinations of the cases develop or change. Assessing and predicting the outcome of these matters involves substantial uncertainties. In the event that the assumptions we used to evaluate these matters change in future periods or new information becomes available, we may be required to record a liability for an adverse outcome. In an effort to mitigate potential adverse consequences of litigation, we could also seek to settle legal proceedings brought against us. We have not recorded any significant reserves for any litigation on our balance sheet.

On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of the State of Delaware (“the Delaware Court”), 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 us or our affiliates. Mr. Brinckerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants (i) TEPPCO, certain of its current and former directors, and certain of its affiliates, (ii) Enterprise Products Partners and certain of its affiliates, (iii) EPCO, and (iv) Dan L. Duncan.

The amended complaint alleges, among other things, that the defendants caused TEPPCO to enter into specified transactions that were unfair to TEPPCO or otherwise unfairly favored us or our affiliates over TEPPCO. These transactions are alleged to include: (i) the joint venture to further expand the Jonah system entered into by TEPPCO and us in August 2006 (the plaintiff alleges that TEPPCO did not receive fair value for allowing us to participate in the joint venture); (ii) the sale by TEPPCO of its Pioneer natural gas processing plant and certain gas processing rights to us in March 2006 (the plaintiff alleges that the purchase price we paid did not provide fair value to TEPPCO); and (iii) certain amendments to TEPPCO’s partnership agreement, including a reduction in the maximum tier of TEPPCO’s incentive distribution rights in exchange for TEPPCO units. The amended complaint seeks (i) rescission of the amendments to

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TEPPCO’s partnership agreement, (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the amended complaint, and (iii) an award to plaintiff of the costs of the action, including fees and expenses of his attorneys and experts. By its Opinion and Order dated November 25, 2008, the Delaware Court dismissed Mr. Brinckerhoff’s individual and putative class action claims with respect to the amendments to TEPPCO’s partnership agreement. We refer to this action and the remaining claims in this action as the “Derivative Action.”

On April 29, 2009, Peter Brinckerhoff and Renee Horowitz, as Attorney in Fact for Rae Kenrow, purported unitholders of TEPPCO, filed separate complaints in the Delaware Court as putative class actions on behalf of other unitholders of TEPPCO, concerning the proposed merger of TEPPCO and TEPPCO GP with Enterprise Products Partners. On May 11, 2009, these actions were consolidated under the caption Texas Eastern Products Pipeline Company, LLC Merger Litigation, C.A. No. 4548-VCL (“Merger Action”). The complaints name as defendants us, Enterprise Products Partners, TEPPCO GP, the directors of TEPPCO GP, EPCO and Dan L. Duncan.

The Merger Action complaints allege, among other things, that the terms of the merger (as proposed as of the time the Merger Action complaints were filed) are grossly unfair to TEPPCO’s unitholders and that the proposed merger is an attempt to extinguish the Derivative Action without consideration. The complaints further allege that the process through which the Special Committee of the ACG Committee of TEPPCO GP was appointed to consider the proposed merger is contrary to the spirit and intent of TEPPCO’s partnership agreement and constitutes a breach of the implied covenant of fair dealing.

The complaints seek relief (i) enjoining the defendants and all persons acting in concert with them from pursuing the proposed merger, (ii) rescinding the proposed merger to the extent it is consummated, or awarding rescissory damages in respect thereof, (iii) directing the defendants to account for all damages suffered or to be suffered by the plaintiffs and the purposed class as a result of the defendants’ alleged wrongful conduct, and (iv) awarding plaintiffs’ costs of the actions, including fees and expenses of their attorneys and experts.

On June 28, 2009, the parties entered into a Memorandum of Understanding pursuant to which Enterprise Products Partners, TEPPCO, EPCO, TEPPCO GP, all other individual defendants and the plaintiffs have proposed to settle the Merger Action and the Derivative Action. The Memorandum of Understanding contemplates that the parties will enter into a stipulation of settlement within 30 days from the date of the Memorandum of Understanding. On August 5, 2009, the parties entered into a Stipulation and Agreement of Compromise, Settlement and Release (the “Settlement Agreement”) contemplated by the Memorandum of Understanding. Pursuant to the Settlement Agreement, the board of directors of TEPPCO GP will recommend to TEPPCO’s unitholders that they approve the adoption of the merger agreement and take all necessary steps to seek unitholder approval for the merger as soon as practicable. Pursuant to the Settlement Agreement, approval of the merger will require, in addition to votes required under TEPPCO’s partnership agreement, that the actual votes cast in favor of the proposal by holders of TEPPCO’s outstanding units, excluding those held by defendants to the Derivative Action, exceed the actual votes cast against the proposal by those holders. The Settlement Agreement further provides that the Derivative Action was considered by TEPPCO GP’s Special Committee to be a significant TEPPCO benefit for which fair value was obtained in the merger consideration.

The Settlement Agreement is subject to customary conditions, including Delaware Court approval. There can be no assurance that the Delaware Court will approve the settlement in the Settlement Agreement. In such event, the proposed settlement as contemplated by the Settlement Agreement may be terminated. Among other things, the plaintiffs’ agreement to settle the Derivative Action and Merger Action litigation, including their agreement to the fairness of the proposed terms and process of the merger negotiations is subject to (i) the drafting and execution of other such documentation as may be required to obtain final Delaware Court approval and dismissal of the actions, (ii) Delaware Court approval and the mailing of the notice of settlement which sets forth the terms of settlement to TEPPCO’s unitholders, (iii) consummation of the proposed merger and (iv) final Delaware Court certification and approval of the

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settlement and dismissal of the actions. See Note 12 for additional information regarding our relationship with TEPPCO, including information related to the proposed merger.

Additionally, on June 29 and 30, 2009, respectively, M. Lee Arnold and Sharon Olesky, purported unitholders of TEPPCO, filed separate complaints in the District Courts of Harris County, Texas, as putative class actions on behalf of other unitholders of TEPPCO, concerning the proposed merger of TEPPCO with us. The complaints name as defendants us, TEPPCO, TEPPCO GP, Enterprise Products Partners, EPCO, Dan L. Duncan, Jerry Thompson, and the board of directors of TEPPCO GP. The allegations in the complaints are similar to the complaints filed in Delaware on April 29, 2009 and seek similar relief.

On February 14, 2007, EPO received a letter from the Environment and Natural Resources Division (“ENRD”) of the U.S. Department of Justice (“DOJ”) related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline (“Magellan Ammonia Pipeline”) owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”), and a previous release of ammonia on September 27, 2004 from the same pipeline. EPO was the operator of this pipeline until July 1, 2008. 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. 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.

The Attorney General of Colorado on behalf of the Colorado Department of Public Health and Environment filed suit against us and others on April 15, 2008 in connection with the construction of a pipeline near Parachute, Colorado. The State sought a temporary restraining order and an injunction to halt construction activities since it alleged that the defendants failed to install measures to minimize damage to the environment and to follow requirements for the pipeline’s stormwater permit and appropriate stormwater plan. The State’s complaint also seeks penalties for the above alleged failures. Defendants and the State agreed to certain stipulations that, among other things, require us to install specified environmental protection measures in the disturbed pipeline right-of-way to comply with regulations. We have complied with the stipulations and the State has dismissed the portions of the complaint seeking the temporary restraining order and injunction. We have entered into a settlement agreement with the State that assesses a fine of which we are responsible for approximately $0.2 million.

In January 2009, the State of New Mexico filed suit in District Court in Santa Fe County, New Mexico, under the New Mexico Air Quality Control Act. The lawsuit arose out of a February 27, 2008 Notice Of Violation issued to Marathon Oil Corp. (“Marathon”) as operator of the Indian Basin natural gas processing facility located in Eddy County, New Mexico. We own a 42.4% undivided interest in the assets comprising the Indian Basin facility. The State alleges violations of its air laws, and Marathon believes there has been no adverse impact to public health or the environment, having implemented voluntary emission reduction measures over the years. The State seeks penalties above $100,000. Marathon continues to work with the State to determine if resolution of the case is possible. We believe that any potential penalties will not have a material impact on our consolidated financial position.

In connection with the dissociation of TEPPCO and us from TOPS (see Note 7), Oiltanking has filed an original petition against Enterprise Offshore Port System, LLC, EPO, TEPPCO O/S Port System, LLC, TEPPCO and TEPPCO GP in the District Court of Harris County, Texas, 61st Judicial District (Cause No. 2009-31367), asserting, among other things, that the dissociation was wrongful and in breach of the TOPS partnership agreement, citing provisions of the agreement that, if applicable, would continue to obligate us and TEPPCO to make capital contributions to fund the project and impose liabilities on us and TEPPCO. Since we believe that our actions in dissociating from TOPS are expressly permitted by, and in accordance with, the terms of the TOPS partnership agreement, we intend to vigorously defend such actions. We have not recorded any reserves for potential liabilities relating to this litigation, although we may determine in future periods that an accrual of reserves for potential liabilities (including costs of

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litigation) should be made. If these payments are substantial, we could experience a material adverse impact on our liquidity.

Regulatory Matters

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs” and including carbon dioxide and methane, may be contributing to climate change. On April 17, 2009, the U.S. Environmental Protection Agency (“EPA”) issued a notice of its proposed finding and determination that emission of carbon dioxide, methane, and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere. The EPA’s finding and determination would allow it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. Although it may take the EPA several years to adopt and impose regulations limiting emissions of GHGs, any such regulation could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, on June 26, 2009, the U.S. House of Representatives approved adoption of the “American Clean Energy and Security Act of 2009,” also known as the “Waxman-Markey cap-and-trade legislation” or “ACESA.” ACESA would establish an economy-wide cap on emissions of GHGs in the United States and would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The U.S. Senate has also begun work on its own legislation for controlling and reducing emissions of GHGs in the United States. Any laws or regulations that may be adopted to restrict or reduce emissions of GHGs would likely require us to incur increased operating costs, and may have an adverse effect on our business and financial position.

Contractual Obligations

Scheduled maturities of long-term debt. With the exception of the issuance of Senior Notes P and routine fluctuations in the balance of our consolidated revolving credit facilities, there have been no significant changes in our consolidated scheduled maturities of long-term debt since those reported in our Recast Form 8-K. See Note 9 for additional information regarding our debt obligations.

Operating lease obligations. During the second quarter of 2009, we entered into a 20-year right-of-way agreement with the Jicarilla Apache Nation in support of continued natural gas gathering activities on our San Juan gathering system in northwest New Mexico. Pending approval of this agreement by the U.S. Department of the Interior, our incremental minimum lease obligations will be $3.0 million for the first year and $2.0 million per year for each of the next succeeding four years. Aggregate minimum lease commitments are $43.3 million over the 20-year contractual term. The agreement also provides for contingent rentals that are calculated annually based on actual throughput volumes and then current natural gas and NGL prices. Our agreement with the Jicarilla Apache Nation does not provide for renewal options beyond the 20-year lease term.

Prior to May 2009, we leased rail and truck terminal facilities in Mont Belvieu, Texas from Martin. At December 31, 2008, our remaining aggregate minimum lease commitments under this agreement were $56.8 million through the contractual term ending in 2023. The lease agreement with Martin was terminated upon our acquisition of such facilities during May 2009. See Note 6 for additional information regarding our acquisition of certain rail and truck terminal facilities from Martin.

Except for the foregoing, there have been no material changes in our operating lease commitments since December 31, 2008.

Purchase obligations. Apart from that discussed below, there have been no material changes in our consolidated purchase obligations since December 31, 2008.

Due to our dissociation from TOPS, our capital expenditure commitments decreased by an estimated $68.0 million from that reported in our Recast Form 8-K. See Note 7 for additional information regarding our dissociation from TOPS.

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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 June 30, 2009, claims against us totaled approximately $4.6 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.

Note 14. Significant Risks and Uncertainties

Insurance Matters

EPCO completed its annual insurance renewal process during the second quarter of 2009. In light of recent hurricane and other weather-related events, the renewal of policies for weather-related risks resulted in significant increases in premiums and certain deductibles, as well as changes in the scope of coverage.

EPCO’s deductible for onshore physical damage from windstorms increased from $10.0 million per storm to $25.0 million per storm. EPCO’s onshore program currently provides $150.0 million per occurrence for named windstorm events compared to $175.0 million per occurrence in the prior year. With respect to offshore assets, the windstorm deductible increased significantly from $10.0 million per storm (with a one-time aggregate deductible of $15.0 million) to $75.0 million per storm. EPCO’s offshore program currently provides $100.0 million in the aggregate compared to $175.0 million in the aggregate for the prior year. For non-windstorm events, EPCO’s deductible for both onshore and offshore physical damage remained at $5.0 million per occurrence. For certain of our major offshore assets, our producer customers have agreed to provide a specified level of physical damage insurance for named windstorms. For example, the producers associated with our Independence Hub and Marco Polo platforms have agreed to cover windstorm generated physical damage costs up to $250.0 million for each platform.

Business interruption coverage in connection with a windstorm event remained unchanged for onshore assets, but was eliminated for offshore assets. Onshore assets covered by business interruption insurance must be out-of-service in excess of 60 days before any losses from business interruption will be covered. Furthermore, pursuant to the current policy, we will now absorb 50% of the first $50.0 million of any loss in excess of deductible amounts for our onshore assets.

In the third quarter of 2008, certain of our onshore and offshore facilities located along the Gulf Coast of Texas and Louisiana were damaged by Hurricanes Gustav and Ike. The disruptions in hydrocarbon production caused by these storms resulted in decreased volumes for some of our pipeline systems, natural gas processing plants, NGL fractionators and offshore platforms, which, in turn, caused a decrease in gross operating margin from these operations. We continue to file property damage claims in connection with the damage caused by these storms. The insurance carriers have notified us that they expect to pay us an initial $25.0 million in business interruption proceeds during the third quarter of 2009 in connection with these storms. We recognize business interruption proceeds as income when they are received in cash.

We received $23.2 million of property damage proceeds during the six months ended June 30, 2009 related to Hurricane Katrina. At June 30, 2009, we have $14.1 million of estimated property damage claims outstanding related to storms that we believe are probable of collection during the next twelve months and $55.7 million thereafter. To the extent we estimate the dollar value of such damages, please be aware that a change in our estimates may occur, if and when additional information becomes available.

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Credit Risk due to Industry Concentrations

Our largest customer for 2008 was LyondellBassell Industries and its affiliates (“LBI”). On January 6, 2009, LBI announced that its U.S. operations had voluntarily filed to reorganize under Chapter 11 of the U.S. Bankruptcy Code. Since LBI filed for Chapter 11 bankruptcy protection and with the support of debtor-in-possession financing, it continues to do business with us. However, we have taken steps to manage our credit exposure to LBI through prepayment requirements and similar remedies. Based on current facts known to us, the bankruptcy of LBI is not expected to have a material adverse effect on our financial condition.

Note 15. Subsequent Events

Loan Agreement with TEPPCO

On August 5, 2009, EPO entered into a Loan Agreement with TEPPCO under which EPO agreed to make an unsecured revolving loan to TEPPCO in an aggregate maximum outstanding principal amount not to exceed $100.0 million. Borrowings under the Loan Agreement mature on the earliest to occur of (i) the consummation of our proposed merger with TEPPCO, (ii) the termination of the related merger agreement in accordance with the provisions thereof, (iii) December 31, 2009, (iv) the date upon which the maturity of the loan is otherwise accelerated upon an event of default, and (v) the date upon which EPO’s commitment to make the loan is terminated by TEPPCO pursuant to the Loan Agreement. Borrowings under the Loan Agreement will bear interest at a floating rate equivalent to the one-month LIBOR Rate (as defined in the Loan Agreement) plus 2%. Interest is payable monthly.

The Loan Agreement provides that amounts borrowed are non-recourse to TEPPCO GP and TEPPCO’s limited partners. The Loan Agreement contains customary events of default, including (i) nonpayment of principal when due or nonpayment of interest or other amounts within three business days of when due, (ii) bankruptcy or insolvency with respect to TEPPCO, (iii) a change of control, or (iv) an event of default under TEPPCO’s revolving credit facility. Any amounts due by TEPPCO under the Loan Agreement will be unconditionally and irrevocably guaranteed by each TEPPCO subsidiary that guarantees TEPPCO’s obligations under its revolving credit facility. EPO’s obligation to fund any borrowings under the Loan Agreement is subject to specified conditions, including the condition that, on and as of the applicable date of funding, no additional amounts are available to TEPPCO pursuant to TEPPCO’s revolving credit facility (either as borrowings or under any letters of credit).

The execution of the Loan Agreement was unanimously approved by the ACG Committees of us and TEPPCO GP.

Settlement Agreement

On August 5, 2009, the parties to the Merger Action and the Derivative Action described in Note 13 entered into the Settlement Agreement contemplated by the Memorandum of Understanding. Pursuant to the Settlement Agreement, the board of directors of TEPPCO GP will recommend to TEPPCO’s unitholders that they approve the adoption of the merger agreement governing TEPPCO’s proposed merger with a subsidiary of Enterprise Products Partners and take all necessary steps to seek unitholder approval for the merger as soon as practicable. Pursuant to the Settlement Agreement, approval of the merger will require, in addition to votes required under TEPPCO’s partnership agreement, that the actual votes cast in favor of the proposal by holders of TEPPCO’s outstanding units, excluding those held by defendants to the Derivative Action, exceed the actual votes cast against the proposal by those holders. The Settlement Agreement further provides that the Derivative Action was considered by TEPPCO’s Special Committee to be a significant TEPPCO benefit for which fair value was obtained in the merger consideration.

Table of Contents

ENTERPRISE PRODUCTS GP, LLC

NOTES TO UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

terminated. See Note 12 for additional information regarding our relationship with TEPPCO, including information related to the proposed merger. See Note 13 for additional information related to the Merger Action and the Derivative Action, including the Settlement Agreement.

		Page No.
Unaudited Condensed Consolidated Balance Sheet at June 30, 2009		2

Notes to Unaudited Condensed Consolidated Balance Sheet
	Note 1 – Company Organization	3
	Note 2 – General Accounting Matters	4
	Note 3 – Accounting for Equity Awards	6
	Note 4 – Derivative Instruments and Hedging Activities	8
	Note 5 – Inventories	15
	Note 6 – Property, Plant and Equipment	15
	Note 7 – Investments in Unconsolidated Affiliates	17
	Note 8 – Intangible Assets and Goodwill	18
	Note 9 – Debt Obligations	19
	Note 10 – Equity	22
	Note 11 – Business Segments	23
	Note 12 – Related Party Transactions	23
	Note 13 – Commitments and Contingencies	27
	Note 14 – Significant Risks and Uncertainties	31
	Note 15 – Subsequent Events	32

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