UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2006

OR

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

For the transition period from                      to                     .

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

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

1100 Louisiana
Houston, Texas 77002
(Address of Principal Executive Offices, Including Zip Code)

(713) 381-6500
(Registrant’s Telephone Number, Including Area Code)

2727 North Loop West
Houston, Texas 77008-1044
(Former Address)

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

Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ     Accelerated filer o      Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

There were 416,698,972 common units of Enterprise Products Partners L.P. outstanding at July 31, 2006. These common units trade on the New York Stock Exchange under the ticker symbol “EPD.”

 

 

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

		Page No.
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Unaudited Condensed Consolidated Balance Sheets			2
Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income			3
Unaudited Condensed Statements of Consolidated Cash Flows			4
Unaudited Condensed Statements of Consolidated Partners’ Equity			5
Notes to Unaudited Condensed Consolidated Financial Statements:
1. Partnership Organization and Basis of Financial Statement Presentation			6
2. General Accounting Policies and Related Matters			7
3. Accounting for Equity Awards			8
4. Financial Instruments			11
5. Inventories			13
6. Property, Plant and Equipment			14
7. Investments in and Advances to Unconsolidated Affiliates			15
8. Business Acquisitions			16
9. Intangible Assets and Goodwill			17
10. Debt Obligations			18
11. Partners’ Equity			20
12. Business Segments			22
13. Related Party Transactions			26
14. Earnings per Unit			28
15. Commitments and Contingencies			30
16. Significant Risks and Uncertainties — Weather-Related Risks			31
17. Supplemental Cash Flow Information			32
18. Condensed Financial Information of Operating Partnership			33
19. Subsequent Events			34
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			36
Item 3. Quantitative and Qualitative Disclosures about Market Risk			60
Item 4. Controls and Procedures			62
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			62
Item 1A. Risk Factors			62
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			63
Item 3. Defaults upon Senior Securities			63
Item 4. Submission of Matters to a Vote of Security Holders			63
Item 5. Other Information			63
Item 6. Exhibits			63
Signatures			66
Second Amendment to Multi-Year Revolving Credit Agreement
Purchase Agreement
Section 302 Certification
Section 302 Certification
Section 1350 Certification
Section 1350 Certification

PART I. FINANCIAL INFORMATION.

Item 1. Financial Statements.

ENTERPRISE PRODUCTS PARTNERS L.P.

		June 30,				December 31,
		2006				2005
ASSETS
Current assets
Cash and cash equivalents		$	24,524			$	42,098
Restricted cash			21,655				14,952
Accounts and notes receivable — trade, net of allowance for doubtful accounts of $20,121 at June 30, 2006 and $25,849 at December 31, 2005			1,324,611				1,448,026
Accounts receivable — related parties			12,691				6,557
Inventories			451,237				339,606
Prepaid and other current assets			169,276				120,208
Total current assets			2,003,994				1,971,447
Property, plant and equipment, net			9,018,275				8,689,024
Investments in and advances to unconsolidated affiliates			464,605				471,921
Intangible assets, net of accumulated amortization of $205,055 at June 30, 2006 and $163,121 at December 31, 2005			909,323				913,626
Goodwill			493,995				494,033
Deferred tax asset			3,444				3,606
Other assets			150,104				47,359
Total assets		$	13,043,740			$	12,591,016
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities
Accounts payable — trade		$	264,368			$	265,699
Accounts payable — related parties			37,597				23,367
Accrued gas payables			1,392,239				1,372,837
Accrued expenses			30,160				30,294
Accrued interest			69,945				71,193
Other current liabilities			188,021				126,881
Total current liabilities			1,982,330				1,890,271
Long-term debt			4,821,401				4,833,781
Other long-term liabilities			131,201				84,486
Minority interest			120,744				103,169
Commitments and contingencies
Partners’ equity
Limited partners
Common units (408,508,111 units outstanding at June 30, 2006 and 389,109,564 units outstanding at December 31, 2005 )			5,851,032				5,542,700
Restricted common units (1,075,017 units outstanding at June 30, 2006 and 751,604 units outstanding at December 31, 2005)			6,580				18,638
General partner			119,535				113,496
Accumulated other comprehensive income			10,917				19,072
Deferred compensation							(14,597	)
Total partners’ equity			5,988,064				5,679,309
Total liabilities and partners’ equity		$	13,043,740			$	12,591,016

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.

		For the Three Months								For the Six Months
		Ended June 30,								Ended June 30,
		2006				2005				2006				2005
REVENUES
Third parties		$	3,404,419			$	2,590,820			$	6,564,418			$	5,088,149
Related parties			113,434				80,948				203,509				139,141
Total			3,517,853				2,671,768				6,767,927				5,227,290
COST AND EXPENSES
Operating costs and expenses
Third parties			3,244,576				2,461,244				6,189,796				4,779,317
Related parties			79,009				68,889				180,652				134,460
Total operating costs and expenses			3,323,585				2,530,133				6,370,448				4,913,777
General and administrative costs
Third parties			5,405				7,591				8,137				12,609
Related parties			10,830				11,119				21,838				20,794
Total general and administrative costs			16,235				18,710				29,975				33,403
Total costs and expenses			3,339,820				2,548,843				6,400,423				4,947,180
EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES			8,012				2,581				12,041				10,860
OPERATING INCOME			186,045				125,506				379,545				290,970
OTHER INCOME (EXPENSE)
Interest expense			(56,333	)			(56,746	)			(114,410	)			(110,159	)
Other, net			3,393				1,245				5,362				2,164
Other expense			(52,940	)			(55,501	)			(109,048	)			(107,995	)
INCOME BEFORE PROVISION FOR INCOME TAXES, MINORITY INTEREST AND CHANGE IN ACCOUNTING PRINCIPLE			133,105				70,005				270,497				182,975
Provision for income taxes			(6,272	)			1,034				(9,164	)			(735	)
INCOME BEFORE MINORITY INTEREST AND CHANGE IN ACCOUNTING PRINCIPLE			126,833				71,039				261,333				182,240
Minority interest			(538	)			(380	)			(2,736	)			(2,325	)
INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE			126,295				70,659				258,597				179,915
Cumulative effect of change in accounting principle (see Note 3)											1,475
NET INCOME		$	126,295			$	70,659			$	260,072			$	179,915
Cash flow financing hedges (see Note 4)			1,638								1,638
Amortization of cash flow financing hedges			(1,052	)			(1,006	)			(2,093	)			(2,001	)
Change in fair value of commodity hedges			(7,951	)							(7,700	)			(1,434	)
COMPREHENSIVE INCOME		$	118,930			$	69,653			$	251,917			$	176,480
ALLOCATION OF NET INCOME:
Limited partners’ interest in net income		$	103,192			$	54,040			$	215,561			$	147,763
General partner interest in net income		$	23,103			$	16,619			$	44,511			$	32,152
EARNINGS PER UNIT: (see Note 14)
Basic income per unit before change in accounting principle		$	0.25			$	0.14			$	0.53			$	0.39
Basic income per unit		$	0.25			$	0.14			$	0.54			$	0.39
Diluted income per unit before change in accounting principle		$	0.25			$	0.14			$	0.53			$	0.39
Diluted income per unit		$	0.25			$	0.14			$	0.54			$	0.39

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.

		For the Six Months
		Ended June,
		2006				2005
OPERATING ACTIVITIES
Net income		$	260,072			$	179,915
Adjustments to reconcile net income to cash flows provided from operating activities:
Depreciation, amortization and accretion in operating costs and expenses			212,768				201,013
Depreciation and amortization in general and administrative costs			3,752				3,490
Amortization in interest expense			487				(370	)
Equity in income of unconsolidated affiliates			(12,041	)			(10,860	)
Distributions received from unconsolidated affiliates			20,348				38,908
Cumulative effect of change in accounting principle			(1,475	)
Operating lease expense paid by EPCO, Inc.			1,056				1,056
Minority interest			2,736				2,325
Gain on sale of assets			(197	)			(5,353	)
Deferred income tax expense			9,180				3,875
Changes in fair market value of financial instruments			(53	)			111
Net effect of changes in operating accounts (see Note 17)			74,692				(296,273	)
Net cash provided from operating activities			571,325				117,837
INVESTING ACTIVITIES
Capital expenditures			(575,419	)			(435,769	)
Contributions in aid of construction costs			34,941				27,032
Proceeds from sale of assets			256				42,267
Decrease (increase) in restricted cash			(6,703	)			13,130
Cash used for business combinations and asset purchases			(38,100	)			(181,079	)
Acquisition of intangible asset							(1,750	)
Advances to Jonah affiliate (see Note 13)			(97,767	)
Investments in unconsolidated affiliates			(14,115	)			(80,650	)
Advances (to) from unconsolidated affiliates			7,120				(1,130	)
Return of investment of unconsolidated affiliate							47,500
Cash used in investing activities			(689,787	)			(570,449	)
FINANCING ACTIVITIES
Borrowings under debt agreements			1,435,000				2,612,345
Repayments of debt			(1,402,000	)			(2,341,007	)
Debt issuance costs							(8,287	)
Distributions paid to partners			(400,474	)			(346,571	)
Distributions paid to minority interests			(4,131	)			(4,154	)
Contributions from minority interests			19,018				23,564
Contribution from general partner related to issuance of restricted units							7
Net proceeds from issuance of common units			453,475				525,204
Cash provided by financing activities			100,888				461,101
NET CHANGE IN CASH AND CASH EQUIVALENTS			(17,574	)			8,489
CASH AND CASH EQUIVALENTS, JANUARY 1			42,098				24,556
CASH AND CASH EQUIVALENTS, JUNE 30		$	24,524			$	33,045

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.

														Accumulated
														Other
		Limited				General				Deferred				Comprehensive
		Partners				Partner				Compensation				Income				Total
Balance, December 31, 2005		$	5,561,338			$	113,496			$	(14,597	)		$	19,072			$	5,679,309
Net income			215,561				44,511												260,072
Operating leases paid by EPCO, Inc.			1,035				21												1,056
Cash distributions to partners			(352,445	)			(47,304	)											(399,749	)
Unit option reimbursements to EPCO, Inc.			(710	)			(15	)											(725	)
Net proceeds from sales of common units			442,832				9,038												451,870
Proceeds from exercise of unit options			1,573				32												1,605
Change in accounting method for equity awards (see Note 3)			(15,814	)			(322	)			14,597								(1,539	)
Amortization of equity awards			4,242				78												4,320
Change in fair value of commodity hedges															(7,700	)			(7,700	)
Interest rate hedging financial instruments recorded as cash flow hedges:
- Change in fair value															1,638				1,638
- Amortization of gain as component of interest expense															(2,093	)			(2,093	)
Balance, June 30, 2006		$	5,857,612			$	119,535			$	—			$	10,917			$	5,988,064

See Notes to Unaudited Condensed Consolidated Financial Statements

ENTERPRISE PRODUCTS PARTNERS L.P.

1. Partnership Organization and Basis of Financial Statement Presentation

Partnership Organization and Formation

     Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Unless the context requires otherwise, references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. and its subsidiaries.

     We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO, Inc. (“EPCO”). We conduct substantially all of our business through our wholly owned subsidiary, Enterprise Products Operating L.P. (our “Operating Partnership”). We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as “Enterprise Products GP”). Enterprise Products GP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded affiliate, the common units of which are listed on the NYSE under the ticker symbol “EPE.” The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), a wholly owned subsidiary of Dan Duncan LLC, the membership interests of which are owned by Dan L. Duncan. We, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO.

     References to “TEPPCO” mean TEPPCO Partners, L.P., a publicly traded Delaware limited partnership, which is an affiliate of us. References to “TEPPCO GP” refer to the general partner of TEPPCO, which is wholly owned by a private company subsidiary of EPCO.

Basis of Presentation of Consolidated Financial Statements

     Our results of operations for the three and six months ended June 30, 2006 are not necessarily indicative of results expected for the full year.

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

     Essentially all of our assets, liabilities, revenues and expenses are recorded at the Operating Partnership level in our consolidated financial statements. We act as guarantor of certain of our Operating Partnership’s debt obligations. See Note 18 for condensed consolidated financial information of our Operating Partnership.

     In our opinion, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for fair presentation. Although we believe our disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) have been condensed or omitted pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC” or “Commission”). These unaudited financial statements should be read in conjunction with our annual report on Form 10-K for the year ended December 31, 2005 (Commission File No. 1-14323).

2. General Accounting Policies and Related Matters

Use of estimates

     In accordance with GAAP, we use estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during each reporting period. Our actual results could differ from these estimates.

New accounting pronouncements

     Emerging Issues Task Force (“EITF”) 04-13, “Accounting for Purchases and Sale of Inventory With the Same Counterparty.” This accounting guidance requires that two or more inventory transactions with the same counterparty should be viewed as a single nonmonetary transaction, if the transactions were entered into in contemplation of one another. Exchanges of inventory between entities in the same line of business should be accounted for at fair value or recorded at carrying amounts, depending on the classification of such inventory. This guidance was effective April 1, 2006, and our adoption of this guidance had no impact on our financial position, results of operations or cash flows.

     EITF 06-3, “How Taxes Collected From Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation).” This accounting guidance requires companies to disclose their policy regarding the presentation of tax receipts on the face of their income statements. This guidance specifically applies to taxes imposed by governmental authorities on revenue-producing transactions between sellers and customers (gross receipts taxes are excluded). This guidance is effective January 1, 2007. As a matter of policy, we report such taxes on a net basis.

     Statement of Financial Accounting Standards (“SFAS”) 155, “Accounting for Certain Hybrid Financial Instruments.” This accounting standard amends SFAS 133, Accounting for Derivative Instruments and Hedging Activities, amends SFAS 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, and resolves issues addressed in Statement 133 Implementation Issue D1, Application of Statement 133 to Beneficial Interests to Securitized Financial Assets. A hybrid financial instrument is one that embodies both an embedded derivative and a host contract. For certain hybrid financial instruments, SFAS 133 requires an embedded derivative instrument be separated from the host contract and accounted for as a separate derivative instrument. SFAS 155 amends SFAS 133 to provide a fair value measurement alternative for certain hybrid financial instruments that contain an embedded derivative that would otherwise be recognized as a derivative separately from the host contract. For hybrid financial instruments within its scope, SFAS 155 allows the holder of the instrument to make a one-time, irrevocable election to initially and subsequently measure the instrument in its entirety at fair value instead of separately accounting for the embedded derivative and host contract. We are evaluating the effect of this recent guidance, which is effective January 1, 2007 for our partnership.

Change in accounting principle and reclassifications

     In January 2006, we adopted the provisions of SFAS 123(R), “Share-Based Payment.” Upon adoption of this accounting standard, we recognized a cumulative effect of change in accounting principle of $1.5 million (a benefit). For additional information regarding our adoption of SFAS 123(R), see Note 3.

Accounting for employee benefit plans

     Dixie Pipeline Company (“Dixie”), a consolidated subsidiary, directly employs the personnel operating its pipeline system. Certain of these employees are eligible to participate in Dixie’s defined contribution plan and pension and postretirement benefit plans. Due to the immaterial nature of Dixie’s employee benefit plans to our consolidated financial position, results of operations and cash flows, our discussion is limited to the following:

     Defined contribution plan. Dixie contributed $0.1 million to its company-sponsored defined contribution plan during the three months ended June 30, 2006 and 2005. During the six months ended June 30, 2006 and 2005, Dixie contributed $0.2 million and $0.1 million to its company-sponsored defined contribution plan, respectively.

     Pension and postretirement benefit plans. Dixie’s net pension benefit costs were $0.2 million for the three months ended June 30, 2006 and 2005. For the six months ended June 30, 2006 and 2005, Dixie’s net pension benefit costs were $0.3 million and $0.2 million, respectively. Dixie’s net postretirement benefit costs were $0.1 million for the three months ended June 30, 2006 and 2005. For the six months ended June 30, 2006 and 2005, Dixie’s net postretirement benefit costs were $0.1 million. During the remainder of 2006, Dixie expects to contribute approximately $0.2 million to its postretirement benefit plan and between $2 million and $4.4 million to its pension plan.

Provision for income taxes

     Prior to the second quarter of 2006, our provision for income taxes related to federal income tax and state franchise and income tax obligations of Seminole and Dixie, which are both corporations and represented our only consolidated subsidiaries that were historically subject to such income taxes. In May 2006, the State of Texas enacted a new business tax (the “Texas Margin Tax”) that replaced the existing state franchise tax. In general, legal entities that do business in Texas are subject to the Texas Margin Tax. Limited partnerships, limited liability companies, corporations, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the Texas Margin Tax. As a result of the change in tax law, our tax status in the State of Texas changed from nontaxable to taxable. The tax is considered an income tax for purposes of adjustments to deferred tax liability as the tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas Margin Tax becomes effective for margin tax reports due on or after January 1, 2008. The Texas Margin Tax due in 2008 will be based on revenues earned during the 2007 fiscal year.

     The Texas Margin Tax is assessed at 1% of Texas-sourced taxable margin. The taxable margin is the lesser of (1) 70% of total revenue or (2) total revenue less (a) cost of goods sold or (b) compensation and benefits. Our deferred tax liability, which is a component of other long-term liabilities on our consolidated balance sheets, reflects the net tax effects of temporary differences related to items such as property, plant and equipment. Therefore, the deferred tax liability is noncurrent. We have calculated and recorded an estimated deferred tax liability of approximately $6.1 million for the Texas Margin Tax. The non-cash offsetting charge of $6.1 million is shown on our unaudited condensed statements of consolidated operations and comprehensive income as a component of provision for income taxes for the three months and six months ended June 30, 2006.

3. Accounting for Equity Awards

     Effective January 1, 2006, we adopted SFAS 123(R) to account for equity awards. Prior to our adoption of SFAS 123(R), we accounted for our equity awards using the intrinsic value method described in Accounting Principles Board Opinion (“APB”) 25, “Accounting for Stock Issued to Employees.” SFAS 123(R) requires us to recognize compensation expense related to our equity awards based on the fair value of the award at the grant date. The fair value of an equity award is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an award is amortized to earnings on a straight-line basis over the requisite service or vesting period.

     Upon our adoption of SFAS 123(R), we recognized a cumulative effect of change in accounting principle of $1.5 million (a benefit) based on SFAS 123(R)’s requirement to recognize compensation expense based upon the grant date fair value of an equity award and the application of an estimated forfeiture rate to unvested awards. In addition, previously recognized deferred compensation expense of $14.6 million related to nonvested (or “restricted”) common units was reversed on January 1, 2006.

     Prior to our adoption of SFAS 123(R), we did not recognize any compensation expense related to unit options; however, compensation expense was recognized in connection with awards granted by EPE Unit L.P. (the “Employee Partnership”) and the issuance of nonvested units. The effects of applying SFAS 123(R) during the three and six months ended June 30, 2006 did not have a material effect on our net income or basic and diluted earnings per unit.

     Since we adopted SFAS 123(R) using the modified prospective method, we have not restated the financial statements of prior periods to reflect this new standard. The following table shows the pro forma effects on our earnings for the three and six months ended June 30, 2005 as if the fair value method of SFAS 123, “Accounting for Stock-Based Compensation” had been used instead of the intrinsic-value method of APB 25. The only equity awards outstanding during the three and six months ended June 30, 2005 were unit options and nonvested units.

		For the				For the
		Three Months				Six Months
		Ended				Ended
		June 30,				June 30,
		2005				2005
Reported net income		$	70,659			$	179,915
Additional unit option-based compensation expense estimated using fair value-based method			(177	)			(354	)
Pro forma net income		$	70,482			$	179,561
Basic and diluted earnings per unit:
As reported and pro forma		$	0.14			$	0.39

Unit options

     Under EPCO’s 1998 Long-Term Incentive Plan (the “1998 Plan”), non-qualified incentive options to purchase a fixed number of our common units may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. When issued, the exercise price of each option grant is equivalent to the market price of the underlying equity on the date of grant. In general, options granted under the 1998 Plan have a vesting period of four years and remain exercisable for ten years from the date of grant.

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

     The fair value of each option is estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the options of seven years, (ii) risk-free interest rates ranging from 3.1% to 6.4%, (iii) an expected distribution yield on our common units ranging from 5.3% to 10%, and (iv) expected unit price volatility on our common units ranging from 20% to 30%. In general, our assumption of expected life represents the period of time that options are expected to be outstanding based on an analysis of historical option activity. Our selection of the risk-free interest rate is based on published yields for U.S. government securities with comparable terms. The expected distribution yield and unit price volatility for our units is estimated based on several factors, which include an analysis of our historical unit price volatility and distribution yield over a period equal to the expected life of the option.

     The information in the following table shows unit option activity under the 1998 Plan.

										Weighted-
										average
						Weighted-				remaining				Aggregate
		Number of				average strike				contractual				Intrinsic
		Units				price				term (in years)				Value (1)
Outstanding at December 31, 2005			2,082,000			$	22.16
Granted			590,000			$	24.85
Exercised			(63,000	)		$	14.75
Forfeited			(45,000	)		$	24.28
Outstanding at June 30, 2006			2,564,000			$	22.92				7.91			$	3,594
Exercisable at June 30, 2006			714,000			$	19.87				5.35			$	3,594

     The total intrinsic value of unit options exercised during the three and six months ended June 30, 2006 was $0.3 million and $0.6 million, respectively. We recognized $0.2 million and $0.3 million of compensation expense associated with unit options during the three and six months ended June 30, 2006, respectively.

     As of June 30, 2006, there was an estimated $1.9 million of total unrecognized compensation cost related to nonvested unit options granted under the 1998 Plan to EPCO employees who work on our behalf. That cost is expected to be recognized over a weighted-average period of 2.8 years.

     During the six months ended June 30, 2006, we received cash of $1.6 million from the exercise of unit options, and our option-related reimbursements to EPCO were $0.7 million.

Nonvested units

     Under the 1998 Plan, we may issue nonvested (or “restricted”) common units to key employees of EPCO and directors of our general partner. The 1998 Plan provides for the issuance of 3,000,000 restricted common units, of which 1,933,088 remain authorized for issuance at June 30, 2006.

     In general, our restricted unit awards allow recipients to acquire the underlying common units (at no cost to the recipient) once a defined vesting period expires, subject to certain forfeiture provisions. The restrictions on such nonvested units generally lapse four years from the date of grant. Compensation expense is recognized on a straight-line basis over the vesting period. The fair value of such restricted units is based on (i) the market price of the underlying common units on the date of grant and (ii) an allowance for forfeitures.

     The following table summarizes information regarding our restricted units for the six months ended June 30, 2006.

						Weighted-
		Number of				average grant
		Units				date fair value
Restricted units at December 31, 2005			751,604			$	24.49
Granted			400,400			$	24.85
Vested			(39,711	)		$	23.91
Forfeited			(37,276	)		$	24.14
Restricted units at June 30, 2006			1,075,017			$	24.66

     The total fair value of restricted units that vested during the three and six months ended June 30, 2006 was $0.9 million and $1.0 million, respectively. During the three and six months ended June 30,

2006, we recognized $1.6 million and $2.3 million of compensation expense, respectively, associated with nonvested units.

     As of June 30, 2006, there was $13.9 million of total unrecognized compensation cost related to nonvested units issued to EPCO employees that work on our behalf. That cost is expected to be recognized over a weighted-average period of 3.1 years.

Employee Partnership

     In connection with the initial public offering of Enterprise GP Holdings in August 2005, the Employee Partnership was formed to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in the Employee Partnership. At inception, the Employee Partnership used $51 million in contributions it received from an affiliate of EPCO (which was admitted as the Class A limited partner of the Employee Partnership as a result of such contribution) to purchase 1,821,428 units of Enterprise GP Holdings in August 2005. Certain EPCO employees, including all of EPE Holdings’ and Enterprise Products GP’s executive officers other than Dan L. Duncan, have been issued Class B limited partner interests without any capital contribution and admitted as Class B limited partners of the Employee Partnership.

     As described in its partnership agreement, the Employee Partnership will be liquidated upon the earlier of (i) August 2010 or (ii) a change in control of Enterprise GP Holdings or its general partner, EPE Holdings. Upon liquidation of the Employee Partnership, units having a fair market value equal to the Class A limited partner’s capital base will be distributed to the Class A limited partner, plus any Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partners as a residual profits interest in the Employee Partnership as an award.

     Prior to our adoption of SFAS 123(R), the estimated value of the profits interest was accounted for in a manner similar to a stock appreciation right. Upon our adoption of SFAS 123(R), we began recognizing compensation expense based upon the estimated grant date fair value of the Class B partnership equity awards.

     The fair value of the Class B partnership equity awards was estimated on the date of grant using a Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards of five years; (ii) a risk-free interest rate of 4.1%; (iii) an expected dividend yield on units of Enterprise GP Holdings of 3%; and (iv) an expected Enterprise GP Holdings unit price volatility of 30%. In general, the methodology we followed to estimate the fair value of the Class B partnership equity awards is similar to that used to estimate the fair value of Enterprise Products Partners’ unit options.

     During the three and six months ended June 30, 2006, we recognized $0.6 million and $1.1 million of compensation expense, respectively, associated with such profits interests. As of June 30, 2006, there was $10.5 million of total unrecognized compensation cost related to the profits interests, of which we estimate our allocable share to be $9.7 million. That cost is expected to be recognized on a straight-line basis through the third quarter of 2010.

4. Financial Instruments

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

Interest Rate Risk Hedging Program

     Our interest rate exposure results from variable and fixed interest rate borrowings under various debt agreements. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt.

     Fair value hedges — Interest rate swaps. As summarized in the following table, we had eleven interest rate swap agreements outstanding at June 30, 2006 that were accounted for as fair value hedges.

Number

Period Covered

Termination

Fixed to

Notional

Hedged Fixed Rate Debt

Of Swaps

by Swap

Date of Swap

Variable Rate (1)

Amount

Senior Notes B, 7.50% fixed rate, due Feb. 2011

1

Jan. 2004 to Feb. 2011

Feb. 2011

7.50% to 8.15%

$50 million

Senior Notes C, 6.375% fixed rate, due Feb. 2013

2

Jan. 2004 to Feb. 2013

Feb. 2013

6.375% to 6.69%

$200 million

Senior Notes G, 5.6% fixed rate, due Oct. 2014

6

4th Qtr. 2004 to Oct. 2014

Oct. 2014

5.6% to 6.14%

$600 million

Senior Notes K, 4.95% fixed rate, due June 2010

2

Aug. 2005 to June 2010

June 2010

4.95% to 5.73%

$200 million

     The total fair value of these eleven interest rate swaps at June 30, 2006 and December 31, 2005, was a liability of $64.9 million and $19.2 million, respectively, with an offsetting decrease in the fair value of the underlying debt. Interest expense for the three months ended June 30, 2006 and 2005 reflects a $1.1 million expense and a $2.9 million benefit from these swap agreements, respectively. For the six months ended June 30, 2006 and 2005, interest expense reflects a $0.9 million expense and a $7.5 million benefit, respectively, from these swap agreements.

     Cash flow hedges — Treasury Locks. During the second quarter of 2006, the Operating Partnership entered into a treasury lock transaction having a notional amount of $250 million. In addition, in July 2006, the Operating Partnership entered into an additional treasury lock transaction having a notional amount of $50 million. A treasury lock is a specialized agreement that fixes the price (or yield) on a specific treasury security for an established period of time. A treasury lock purchaser is protected from a rise in the yield of the underlying treasury security during the lock period. The Operating Partnership’s purpose of entering into these transactions was to hedge the underlying U.S. treasury rate related to its anticipated issuance of subordinated debt. In July 2006, the Operating Partnership issued $300 million in principal amount of its Junior Notes A (see Note 19). Each of the treasury lock transactions was designated as a cash flow hedge under SFAS 133. In July 2006, the Operating Partnership elected to terminate these treasury lock transactions and recognized a minimal gain.

Commodity Risk Hedging Program

     The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with such products, we may enter into commodity financial instruments. The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas, NGLs or certain petrochemical products.

     The fair value of our commodity financial instrument portfolio at June 30, 2006 and December 31, 2005 was a liability of $7.8 million and $0.1 million, respectively. During the three and six months ended June 30, 2006, we recorded $5.7 million and $5.3 million of expense related to our commodity financial instruments, respectively, which is included in operating costs and expenses on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income. We recorded nominal amounts of earnings from our commodity financial instruments during the three and six months ended June 30, 2005.

5. Inventories

     The following table shows our inventory amounts at the dates indicated:

		June 30,				December 31,
		2006				2005
Working inventory		$	406,169			$	279,237
Forward-sales inventory			45,068				60,369
Inventory		$	451,237			$	339,606

     Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs, and petrochemical products that are available for sale or used by us in the provision of services. Our forward sales inventory consists of segregated NGL and natural gas volumes dedicated to the fulfillment of forward-sales contracts. Both inventories are valued at the lower of average cost or market.

     Costs and expenses, as shown on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income, include cost of sales related to the sale of inventories. For the three months ended June 30, 2006 and 2005, such consolidated cost of sales amounts were $3 billion and $2.2 billion, respectively. We recorded $5.7 billion and $4.3 billion of such consolidated cost of sales amounts for the six months ended June 30, 2006 and 2005, respectively.

     Due to fluctuating commodity prices in the NGL, natural gas and petrochemical industry, we recognize lower of cost or market adjustments when the carrying values of our inventories exceed their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized. For the three months ended June 30, 2006 and 2005, we recognized $0.3 million and $7.4 million, respectively, of lower of cost or market adjustments. We recorded $12 million and $17 million of such adjustments for the six months ended June 30, 2006 and 2005, respectively.

6. Property, Plant and Equipment

     The following table shows our property, plant and equipment and accumulated depreciation at the dates indicated:

		Estimated
		Useful Life				June 30,				December 31,
		in Years				2006				2005
Plants and pipelines (1)			5–35	(5)		$	8,489,508			$	8,209,580
Underground and other storage facilities (2)			5–35	(6)			552,458				549,923
Platforms and facilities (3)			23–31				161,880				161,807
Transportation equipment (4)			3–10				22,245				24,939
Land							38,589				38,757
Construction in progress							1,074,165				854,595
Total							10,338,845				9,839,601
Less accumulated depreciation							1,320,570				1,150,577
Property, plant and equipment, net						$	9,018,275			$	8,689,024

     Depreciation expense for the three months ended June 30, 2006 and 2005 was $86.9 million and $79.2 million, respectively. We recorded $170.4 million and $158.1 million of depreciation expense for the six months ended June 30, 2006 and 2005, respectively. Capitalized interest on our construction projects for the three months ended June 30, 2006 and 2005 was $12.4 million and $3.2 million, respectively. We recorded $21.6 million and $7.6 million of capitalized interest on our construction projects for the six months ended June 30, 2006 and 2005, respectively.

7. Investments in and Advances to Unconsolidated Affiliates

          We own interests in a number of related businesses that are accounted for using the equity method. Our investments in and advances to unconsolidated affiliates are grouped according to the business segment to which they relate. For a general discussion of our business segments, see Note 12. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated.

		Ownership				Investments in and advances to
		Percentage at				Unconsolidated Affiliates at
		June 30,				June 30,				December 31,
		2006				2006				2005
NGL Pipelines & Services:
Venice Energy Services Company, LLC (“VESCO”)			13.1	%		$	38,609			$	39,689
K/D/S Promix LLC (“Promix”)			50	%			55,330				65,103
Baton Rouge Fractionators LLC (“BRF”)			32.3	%			26,096				25,584
Onshore Natural Gas Pipelines & Services:
Evangeline (1)			49.5	%			4,547				3,151
Coyote Gas Treating, LLC (“Coyote”)			50	%			1,510				1,493
Offshore Pipelines & Services:
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)			36	%			62,296				62,918
Cameron Highway Oil Pipeline Company (“Cameron Highway”)			50	%			62,789				58,207
Deepwater Gateway, L.L.C. (“Deepwater Gateway”)			50	%			115,628				115,477
Neptune Pipeline Company, L.L.C. (“Neptune”)			25.67	%			67,405				68,085
Nemo Gathering Company, LLC (“Nemo”)			33.92	%			10,527				12,157
Petrochemical Services:
Baton Rouge Propylene Concentrator, LLC (“BRPC”)			30	%			14,870				15,212
La Porte (2)			50	%			4,998				4,845
Total						$	464,605			$	471,921

          On occasion, the price we pay to purchase an equity interest in a company exceeds the underlying book capital account we acquire. Such excess cost amounts are included within our investments in and advances to unconsolidated affiliates. At June 30, 2006, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost amounts totaling $47 million, all of which was attributed to values in excess of the underlying tangible asset values. Amortization of such excess cost amounts was $0.6 million and $0.5 million during the three months ended June 30, 2006 and 2005, respectively. For the six months ended June 30, 2006 and 2005, amortization of such amounts was $1.1 million and $1.2 million, respectively.

          The following table shows our equity in income of unconsolidated affiliates by business segment for the periods indicated:

		For the Three Months								For the Six Months
		Ended June 30,								Ended June 30,
		2006				2005				2006				2005
NGL Pipelines & Services		$	1,924			$	2,837			$	3,442			$	7,285
Onshore Natural Gas Pipelines & Services			904				682				1,506				1,262
Offshore Pipelines & Services (1)			4,769				(1,075	)			6,703				1,900
Petrochemical Services			415				137				390				413
Total		$	8,012			$	2,581			$	12,041			$	10,860

Summarized financial information of unconsolidated affiliates

          The following table presents unaudited income statement data for our current unconsolidated affiliates, aggregated by business segment, for the periods indicated (on a 100% basis).

		Summarized Income Statement Information for the Three Months Ended
		June 30, 2006												June 30, 2005
						Operating				Net								Operating				Net
		Revenues				Income (Loss)				Income (Loss)				Revenues				Income				Income (Loss)
NGL Pipelines & Services (1)		$	60,220			$	(2,238	)		$	(1,785	)		$	69,382			$	14,060			$	14,392
Onshore Natural Gas Pipelines & Services			77,381				2,363				1,722				82,054				4,055				1,251
Offshore Pipelines & Services (2)			39,554				20,166				12,804				37,289				18,886				(10,468	)
Petrochemical Services			5,557				1,645				1,665				3,952				720				730

		Summarized Income Statement Information for the Six Months Ended
		June 30, 2006												June 30, 2005
						Operating				Net								Operating				Net
		Revenues				Income (Loss)				Income (Loss)				Revenues				Income				Income (Loss)
NGL Pipelines & Services (1)		$	80,506			$	(24,363	)		$	(23,463	)		$	139,346			$	27,833			$	28,431
Onshore Natural Gas Pipelines & Services			159,723				4,705				2,914				135,048				6,202				2,323
Offshore Pipelines & Services (2)			71,250				31,096				16,484				67,652				33,796				(1,565	)
Petrochemical Services			9,425				1,831				1,875				8,047				1,849				1,871

8. Business Acquisitions

          In March 2006, we paid $38.1 million to TEPPCO for its Pioneer natural gas processing plant located in Opal, Wyoming and certain natural gas processing rights related to production from the Jonah and Pinedale fields located in the Greater Green River Basin in Wyoming. This acquisition was accounted for under the purchase method of accounting and, accordingly, the cost has been allocated based on estimated preliminary fair values as follows:

Property, plant and equipment, net		$	469
Intangible assets			37,631
Total assets acquired		$	38,100
Total consideration given		$	38,100

          Management developed the fair value estimates underlying this preliminary purchase price allocation using recognized business valuation techniques.

          After completing this acquisition, we commenced construction to increase the capacity of the Pioneer natural gas processing plant, and started work on a related cryogenic natural gas processing facility. Upon completion of the cryogenic natural gas processing facility, we will have the required capacity to process natural gas production from the Jonah and Pinedale fields that is expected to be transported to our Wyoming facilities as a result of the contract rights we acquired from TEPPCO. See Note 9 for information regarding the intangible assets recorded in connection with this acquisition.

          See Note 19 for subsequent events involving (i) our acquisition of natural gas pipeline assets located in South Texas in July 2006 and (ii) our acquisition of an NGL pipeline from ExxonMobil in August 2006.

9. Intangible Assets and Goodwill

Identifiable Intangible assets

          The following table summarizes our intangible assets by segment. Our intangible assets primarily consist of contracts and customer relationships.

		At June 30, 2006												At December 31, 2005
		Gross				Accum.				Carrying				Accum.				Carrying
Business Segment		Value				Amort.				Value				Amort.				Value
NGL Pipelines & Services (1)		$	392,894			$	(92,150	)		$	300,744			$	(79,485	)		$	275,778
Onshore Natural Gas Pipelines & Services			457,798				(60,761	)			397,037				(43,955	)			413,843
Offshore Pipelines & Services			207,012				(43,947	)			163,065				(32,480	)			174,532
Petrochemical Services			56,674				(8,197	)			48,477				(7,201	)			49,473
Total		$	1,114,378			$	(205,055	)		$	909,323			$	(163,121	)		$	913,626

(1)

During the first six months of 2006, we recorded an additional $37.6 million of intangible assets in connection with our acquisition of the Pioneer natural gas processing plant and associated natural gas processing rights. The value we assigned to these processing rights will be amortized to earnings using methods that closely resemble the pattern in which the economic benefits of the underlying natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. Our estimate of the useful life of each resource base is based on a number of factors, including third-party reserve estimates, the economic viability of production and exploration activities and other industry factors.

          The following table shows amortization expense by segment associated with our intangible assets for the periods indicated:

		For the Three Months								For the Six Months
		Ended June 30,								Ended June 30,
		2006				2005				2006				2005
NGL Pipelines & Services		$	6,304			$	7,045			$	12,665			$	13,472
Onshore Natural Gas Pipelines & Services			8,348				8,847				16,806				17,820
Offshore Pipelines & Services			5,633				6,488				11,467				13,210
Petrochemical Services			497				508				996				997
Total		$	20,782			$	22,888			$	41,934			$	45,499

          For the remainder of 2006, amortization expense associated with our intangible assets is currently estimated at $40.6 million.

Goodwill

          The following table summarizes our goodwill amounts by segment at the dates indicated. Of the $494 million of goodwill at June 30, 2006, $387.1 million was recorded in connection with the merger of GulfTerra Energy Partners, L.P. (“GulfTerra”) with a wholly owned subsidiary of Enterprise Products Partners in September 2004.

		June 30,				December 31,
		2006				2005
NGL Pipelines & Services		$	54,942			$	54,960
Onshore Natural Gas Pipelines & Services			282,977				282,997
Offshore Pipelines & Services			82,386				82,386
Petrochemical Services			73,690				73,690
Totals		$	493,995			$	494,033

10. Debt Obligations

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

		June 30,				December 31,
		2006				2005
Operating Partnership debt obligations:
Multi-Year Revolving Credit Facility, variable rate, due October 2011 (1)		$	530,000			$	490,000
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010			54,000				54,000
Senior Notes B, 7.50% fixed-rate, due February 2011			450,000				450,000
Senior Notes C, 6.375% fixed-rate, due February 2013			350,000				350,000
Senior Notes D, 6.875% fixed-rate, due March 2033			500,000				500,000
Senior Notes E, 4.00% fixed-rate, due October 2007			500,000				500,000
Senior Notes F, 4.625% fixed-rate, due October 2009			500,000				500,000
Senior Notes G, 5.60% fixed-rate, due October 2014			650,000				650,000
Senior Notes H, 6.65% fixed-rate, due October 2034			350,000				350,000
Senior Notes I, 5.00% fixed-rate, due March 2015			250,000				250,000
Senior Notes J, 5.75% fixed-rate, due March 2035			250,000				250,000
Senior Notes K, 4.950% fixed-rate, due June 2010			500,000				500,000
Dixie Revolving Credit Facility, variable rate, due June 2007			10,000				17,000
Debt obligations assumed from GulfTerra			5,068				5,068
Total principal amount			4,899,068				4,866,068
Other, including unamortized discounts and premiums and changes in fair value (2)			(77,667	)			(32,287	)
Long-term debt		$	4,821,401			$	4,833,781
Standby letters of credit outstanding		$	46,558			$	33,129

(1)		In June 2006, the Operating Partnership executed a second amendment (the “Second Amendment”) to the credit agreement governing its Multi-Year Revolving Credit Facility. The Second Amendment, among other things, extends the maturity date of amounts borrowed under the Multi-Year Revolving Credit Facility from October 2010 to October 2011 with respect to $1.2 billion of the commitments. Borrowings with respect to the remaining $48 million in commitments mature in October 2010.
(2)		The June 30, 2006 amount includes $64 million related to fair value hedges and $13.7 million in net unamortized discounts. The December 31, 2005 amount includes $18.2 million related to fair value hedges and $14.1 million in net unamortized discounts.

Parent-Subsidiary guarantor relationships

          We guarantee the debt obligations of our Operating Partnership, with the exception of the Dixie revolving credit facility and the senior subordinated notes assumed from GulfTerra. If the Operating Partnership were to default on any debt we guarantee, we would be responsible for full repayment of that obligation.

Operating Partnership debt obligations

          Apart from that discussed below, there have been no significant changes in the terms of our Operating Partnership’s debt obligations since those reported in our annual report on Form 10-K for the year ended December 31, 2005.

          In March 2006, we generated net proceeds of $430 million in connection with the sale of 18,400,000 of our common units in an underwritten equity offering. Subsequently, this amount was contributed to the Operating Partnership, which, in turn, used this amount to temporarily reduce debt outstanding under its Multi-Year Revolving Credit Facility.

          In June 2006, the Operating Partnership executed a second amendment (the “Second Amendment”) to the credit agreement governing its Multi-Year Revolving Credit Facility. The Second Amendment, among other things, extends the maturity date of the Multi-Year Revolving Credit Facility from October 2010 to October 2011 with respect to $1.2 billion of the commitments. Borrowings with respect to $48 million in commitments mature in October 2010. The Second Amendment also modifies the Operating Partnership’s financial covenants to, among other things, allow the Operating Partnership to

amendment increased the face amount of the letters of credit required to be issued by the Operating Partnership and an affiliate of our joint venture partner from $18.4 million each to $36.8 million each.

          Also, the amendment specifies that Cameron Highway cannot make distributions to its partners during the period beginning March 30, 2006 and ending on the earlier of (i) December 31, 2007 or (ii) the date on which Cameron Highway’s debt service coverage ratios are not less than 1.5 to 1 for three consecutive fiscal quarters. In order for Cameron Highway to resume paying distributions to its partners, no default or event of default can be present or continuing at the date Cameron Highway desires to start paying such distributions.

          Amendment of Poseidon debt. In May 2006, Poseidon amended its revolving credit facility to, among other things, reduce commitments from $170 million to $150 million, extend the maturity date from January 2008 to May 2011 and lower the borrowing rate.

11. Partners’ Equity

          Our common units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights and privileges available to them under our Fifth Amended and Restated Agreement of Limited Partnership (together with all amendments thereto, the “Partnership Agreement”). We are managed by our general partner, Enterprise Products GP.

Capital accounts

          In accordance with our Partnership Agreement, capital accounts are maintained for our general partner and our limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements.

          Our Partnership Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that our limited partners and general partner will receive. The Partnership Agreement also contains provisions for the allocation of net earnings and losses to our limited partners and general partner. For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests. Normal income and loss allocations according to percentage interests are done only after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated 100% to our general partner.

Equity offerings and registration statements

          In general, the Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by Enterprise Products GP in its sole discretion (subject, under certain circumstances, to the approval of our unitholders). The following table reflects the number of common units issued and the net proceeds received from each public offering during the six months ended June 30, 2006:

						Net Proceeds from Sale of Common Units
		Number of				Contributed				Contributed by
Month of		common units				by Limited				General
Offering		issued				Partners				Partner				Total
February 2006			418,190			$	9,972			$	203			$	10,175
March 2006			18,400,000				421,419				8,601				430,020
May 2006			477,646				11,441				234				11,675
			19,295,836			$	442,832			$	9,038			$	451,870

          We have a universal shelf registration statement on file with the SEC registering the issuance of up to $4 billion of equity and debt securities. After taking into account the past issuance of securities under this universal registration statement, we can issue approximately $3 billion of additional securities under this registration statement as of June 30, 2006.

          In July 2006, we issued approximately 7.1 million of our common units as partial consideration for our acquisition of natural gas pipeline assets located in South Texas. We are obligated to file a registration statement with the SEC for the resale of these common units. See Note 19 for additional information regarding this subsequent event.

Summary of limited partner transactions

          The following table details the changes in limited partners’ equity since December 31, 2005:

		Limited Partners
						Restricted
		Common				Common
		units				units				Total
Balance, December 31, 2005		$	5,542,700			$	18,638			$	5,561,338
Net income			215,103				458				215,561
Operating leases paid by EPCO			1,033				2				1,035
Cash distributions to partners			(351,787	)			(658	)			(352,445	)
Unit option reimbursements to EPCO			(710	)							(710	)
Net proceeds from sales of common units			442,832								442,832
Proceeds from exercise of unit options			1,573								1,573
Change in accounting method for equity awards (see Note 3)			(896	)			(14,918	)			(15,814	)
Amortization of equity awards			1,184				3,058				4,242
Balance, June 30, 2006		$	5,851,032			$	6,580			$	5,857,612

Unit history

          The following table details the outstanding balance of each class of units for the periods and at the dates indicated:

		Limited Partners
						Restricted
		Common				Common
		units				units
Balance, December 31, 2005			389,109,564				751,604
Common units issued in February 2006			418,190
Common units issued in February 2006 in connection with exercises of unit options			29,000
Restricted common units issued in February 2006							17,500
Vesting of restricted units in February 2006			2,434				(2,434	)
Common units issued in connection with March 2006 public offering			18,400,000
Forfeiture of restricted units in March 2006							(26,021	)
Vesting of restricted units in April 2006			37,277				(37,277	)
Forfeiture of restricted units in April 2006							(1,000	)
Common units issued in May 2006			477,646
Common units issued in May 2006 in connection with exercises of unit options			34,000
Restricted common units issued in May 2006							382,900
Forfeiture of restricted units in May 2006							(1,000	)
Forfeiture of restricted units in June 2006							(9,255	)
Balance, June 30, 2006			408,508,111				1,075,017

Distributions

          As an incentive, Enterprise Products GP’s percentage interest in our quarterly cash distributions is increased after certain specified target levels of quarterly distribution rates are met. Enterprise Products GP’s quarterly incentive distribution thresholds are as follows:

	•		2% of quarterly cash distributions up to $0.253 per unit;
	•		15% of quarterly cash distributions from $0.253 per unit up to $0.3085 per unit; and
	•		25% of quarterly cash distributions that exceed $0.3085 per unit.
			Our quarterly cash distributions for 2006 are presented in the following table:

Cash Distribution History

Distribution

Record

Payment

per Unit

Date

Date

1st Quarter 2006

$

0.4450

Apr. 28, 2006

May 10, 2006

2nd Quarter 2006

$

0.4525

Jul. 31, 2006

Aug. 10, 2006

Accumulated other comprehensive income

          The following table summarizes transactions affecting our accumulated other comprehensive income since December 31, 2005.

										Accumulated
						Interest				Other
		Commodity				Rate				Comprehensive
		Financial				Financial				Income
		Instruments				Instruments				Balance
Balance, December 31, 2005						$	19,072			$	19,072
Change in fair value of commodity financial instruments		$	(7,700	)							(7,700	)
Reclassification of gain on settlement of interest rate financial instruments							(2,093	)			(2,093	)
Reclassification of change in fair value of interest rate financial instruments							1,638				1,638
Balance, June 30, 2006		$	(7,700	)		$	18,617			$	10,917

          During the remainder of 2006, we will reclassify $2.1 million from accumulated other comprehensive income to earnings as a reduction in consolidated interest expense.

12. 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 technology employed) and products produced and/or sold.

          We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The GAAP measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

          We define total (or consolidated) segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expense; (ii) operating lease expenses for which we do not have the payment obligation; (iii) gains and losses on the sale of assets; and (iv) general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for

income taxes, minority interest, extraordinary charges and the cumulative effect of changes in accounting principles. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intersegment and intrasegment transactions.

          Segment revenues and operating costs and expenses include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Our consolidated revenues reflect the elimination of all material intercompany (both intersegment and intrasegment) transactions.

          We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of customers and/or suppliers. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations.

          Our integrated midstream energy asset system (including the midstream energy assets of our equity method investees) provides services to producers and consumers of natural gas, NGLs and petrochemicals. Our asset system has multiple entry points. In general, hydrocarbons can enter our asset system through a number of ways, such as an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an NGL gathering pipeline, an NGL fractionator, an NGL storage facility, an NGL transportation or distribution pipeline or an onshore natural gas pipeline. At each link along this asset system, we typically earn revenues based on volume or receive an ownership of products such as NGLs.

          Many of our equity investees are present within our integrated midstream asset system. For example, we have ownership interests in several offshore natural gas and crude oil pipelines. Other examples include our use of the Promix NGL fractionator to process mixed NGLs extracted by our gas plants. The fractionated NGLs we receive from Promix can then be sold in our NGL marketing activities. Given the integral nature of our equity investees to our operations, we believe the treatment of earnings from our equity method investees as a component of gross operating margin and operating income is appropriate.

          Our consolidated revenues were earned in the United States and derived from a wide customer base. The majority of our plant-based operations are located in Texas, Louisiana, Mississippi and New Mexico. Our natural gas, NGL and crude oil pipelines are located in a number of regions of the United States including (i) the Gulf of Mexico offshore Texas and Louisiana; (ii) the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and (iii) certain regions of the central and western United States. Our marketing activities are headquartered in Houston, Texas and serve customers in a number of regions of the United States including the Gulf Coast, West Coast and Mid-Continent areas.

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

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

		For the Three Months								For the Six Months
		Ended June 30,								Ended June 30,
		2006				2005				2006				2005
Revenues (1)		$	3,517,853			$	2,671,768			$	6,767,927			$	5,227,290
Less: Operating costs and expenses (1)			(3,323,585	)			(2,530,133	)			(6,370,448	)			(4,913,777	)
Add: Equity in income of unconsolidated affiliates (1)			8,012				2,581				12,041				10,860
Depreciation, amortization and accretion in operating costs and expenses (2)			107,952				101,048				212,768				201,013
Operating lease expense paid by EPCO (2)			528				528				1,056				1,056
Loss (gain) on sale of assets in operating costs and expenses (2)			(136	)			83				(197	)			(5,353	)
Total segment gross operating margin		$	310,624			$	245,875			$	623,147			$	521,089

          A reconciliation total segment gross operating margin to operating income and income before provision for income taxes, minority interest and the cumulative effect of change in accounting principle follows:

		For the Three Months								For the Six Months
		Ended June 30,								Ended June 30,
		2006				2005				2006				2005
Total segment gross operating margin		$	310,624			$	245,875			$	623,147			$	521,089
Adjustments to reconcile total gross operating margin to operating income:
Depreciation, amortization and accretion in operating costs and expenses			(107,952	)			(101,048	)			(212,768	)			(201,013	)
Operating lease expense paid by EPCO			(528	)			(528	)			(1,056	)			(1,056	)
Gain (loss) on sale of assets in operating costs and expenses			136				(83	)			197				5,353
General and administrative costs			(16,235	)			(18,710	)			(29,975	)			(33,403	)
Consolidated operating income			186,045				125,506				379,545				290,970
Other expense			(52,940	)			(55,501	)			(109,048	)			(107,995	)
Income before provision for income taxes, minority interest and cumulative effect of change in accounting principle		$	133,105			$	70,005			$	270,497			$	182,975

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

		Reportable Segments
		NGL				Onshore				Offshore								Adjustments
		Pipelines				Pipelines				Pipelines				Petrochemical				and				Consolidated
		& Services				& Services				& Services				Services				Eliminations				Totals
Revenues from third parties:
Three months ended June 30, 2006		$	2,553,212			$	308,410			$	29,506			$	513,291							$	3,404,419
Three months ended June 30, 2005			1,945,196				259,213				31,984				354,427								2,590,820
Six months ended June 30, 2006			4,891,908				721,411				51,858				899,241								6,564,418
Six months ended June 30, 2005			3,802,650				506,147				61,532				717,820								5,088,149
Revenues from related parties:
Three months ended June 30, 2006			37,101				75,914				419												113,434
Three months ended June 30, 2005			1,858				78,816				253				21								80,948
Six months ended June 30, 2006			44,049				158,869				591												203,509
Six months ended June 30, 2005			3,620				135,031				439				51								139,141
Intersegment and intrasegment revenues:
Three months ended June 30, 2006			1,077,547				31,588				390				103,449			$	(1,212,974	)
Three months ended June 30, 2005			767,030				8,400				432				87,137				(862,999	)
Six months ended June 30, 2006			1,973,792				59,729				703				186,266				(2,220,490	)
Six months ended June 30, 2005			1,496,707				18,417				628				141,887				(1,657,639	)
Total revenues:
Three months ended June 30, 2006			3,667,860				415,912				30,315				616,740				(1,212,974	)			3,517,853
Three months ended June 30, 2005			2,714,084				346,429				32,669				441,585				(862,999	)			2,671,768
Six months ended June 30, 2006			6,909,749				940,009				53,152				1,085,507				(2,220,490	)			6,767,927
Six months ended June 30, 2005			5,302,977				659,595				62,599				859,758				(1,657,639	)			5,227,290
Equity in income in unconsolidated affiliates:
Three months ended June 30, 2006			1,924				904				4,769				415								8,012
Three months ended June 30, 2005			2,837				682				(1,075	)			137								2,581
Six months ended June 30, 2006			3,442				1,506				6,703				390								12,041
Six months ended June 30, 2005			7,285				1,262				1,900				413								10,860
Gross operating margin by individual business segment and in total:
Three months ended June 30, 2006			146,414				86,651				20,515				57,044								310,624
Three months ended June 30, 2005			120,328				84,903				22,034				18,610								245,875
Six months ended June 30, 2006			317,364				183,454				37,767				84,562								623,147
Six months ended June 30, 2005			273,632				164,261				45,258				37,938								521,089
Segment assets:
At June 30, 2006			3,143,499				3,557,642				733,047				509,922				1,074,165				9,018,275
At December 31, 2005			3,075,048				3,622,318				632,222				504,841				854,595				8,689,024
Investments in and advances to unconsolidated affiliates (see Note 7):
At June 30, 2006			120,035				6,057				318,645				19,868								464,605
At December 31, 2005			130,376				4,644				316,844				20,057								471,921
Intangible Assets (see Note 9):
At June 30, 2006			300,744				397,037				163,065				48,477								909,323
At December 31, 2005			275,778				413,843				174,532				49,473								913,626
Goodwill (see Note 9):
At June 30, 2006			54,942				282,977				82,386				73,690								493,995
At December 31, 2005			54,960				282,997				82,386				73,690								494,033