10-Q

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                     .

Commission file number: 1-14323

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.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	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

2

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

AND COMPREHENSIVE INCOME

(Dollars in thousands, except per unit amounts)

	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

3

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in thousands)

	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

4

ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY

(See Note 11 for Unit History and Detail of Changes in Limited Partners’ Equity)

(Dollars in thousands)

										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

5

ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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).

6

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:

7

     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.

8

     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.

9

     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

(1) Aggregate intrinsic value reflects fully vested unit options at June 30, 2006.

     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,

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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.

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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

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

     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.

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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.

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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

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

     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.

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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

(1)	Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively.
(2)	Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.

          On occasion, the price we pay to 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

(1) Equity earnings from Cameron Highway for the three and six months ended June 30, 2005 were reduced by a charge of $11.5 million for costs associated with the refinancing of Cameron Highway’s project debt in June 2005. The reduction in equity earnings from Cameron Highway for the three and six months ended June 30, 2005, is offset by increases in equity earnings from investments we acquired in connection with the GulfTerra Merger.

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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

(1)	The decrease in earnings generated by the unconsolidated affiliates within our NGL Pipelines & Services segment is primarily attributable to losses incurred by VESCO due to the effects of Hurricane Katrina.
(2)	Earnings for Cameron Highway for the three months ended June 30, 2005 were reduced by a charge of $11.5 million for costs associated with the refinancing of Cameron Highway’s project debt in June 2005.

	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

(1)	The decrease in earnings generated by the unconsolidated affiliates within our NGL Pipelines & Services segment is primarily attributable to losses incurred by VESCO due to the effects of Hurricane Katrina.
(2)	Earnings for Cameron Highway for the six months ended June 30, 2005 were reduced by a charge of $11.5 million for costs associated with the refinancing of Cameron Highway’s project debt in June 2005.

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.

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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

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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

18

include in the calculation of its Consolidated EBITDA (as defined in the credit agreement) pro forma adjustments for material capital projects. In addition, the Second Amendment allows for the issuance of hybrid debt, such as the $300 million in principal amount of fixed/floating unsecured junior subordinated notes issued by the Operating Partnership in July 2006 (see Note 19).

Covenants

          We were in compliance with the covenants of our consolidated debt agreements at June 30, 2006 and December 31, 2005.

Information regarding variable interest rates paid

          The following table shows the range of interest rates paid and weighted-average interest rate paid on our consolidated variable-rate debt obligations during the six months ended June 30, 2006.

	Range of	Weighted-average
	interest rates	interest rate
	paid	paid
Operating Partnership’s Multi-Year Revolving Credit Facility	4.87% to 8.00%		5.35	%
Dixie Revolving Credit Facility	4.67% to 5.55%		5.00	%

Consolidated debt maturity table

          Our scheduled maturities of debt principal amounts over the next five years and in total thereafter are presented in the following table. No amounts are currently due in 2006 or 2008.

2007	$	510,000
2009		500,000
2010		607,068
Thereafter		3,282,000
Total scheduled principal payments	$	4,899,068

Joint venture debt obligations

          We have three unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at June 30, 2006, (ii) total debt of each unconsolidated affiliate at June 30, 2006 (on a 100% basis to the joint venture) and (iii) the corresponding scheduled maturities of such debt.

	Our					Scheduled Maturities of Debt
	Ownership															After
	Interest			Total		2006		2007		2008		2009		2010		2010
Cameron Highway		50.0	%	$	415,000					$	25,000	$	25,000	$	50,000	$	315,000
Poseidon		36.0	%		92,000												92,000
Evangeline		49.5	%		30,650	$	5,000	$	5,000		5,000		5,000		10,650
Total				$	537,650	$	5,000	$	5,000	$	30,000	$	30,000	$	60,650	$	407,000

          The credit agreements of our joint ventures contain various affirmative and negative covenants, including financial covenants. Our joint ventures were in compliance with all such covenants at June 30, 2006.

          Amendment of Cameron Highway debt. In March 2006, Cameron Highway amended the note purchase agreement governing its senior secured notes to primarily address the effect of reduced deliveries of crude oil to Cameron Highway resulting from production delays. In general, this amendment modified certain financial covenants in light of production forecasts made by management. In addition, the

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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

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          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

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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

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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.

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          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

(1)	These amounts are taken from our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income.
(2)	These non-cash expenses are taken from the operating activities section of our Unaudited Condensed Statements of Consolidated Cash Flows.

          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

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          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

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          Revenues from the sale and marketing of NGL products within the NGL Pipelines & Services business segment accounted for 69% and 66% of total consolidated revenues for the three months ended June 30, 2006 and 2005, and 68% and 66% for the six months ended June 30, 2006 and 2005, respectively. Revenues from the sale and marketing of petrochemical products within the Petrochemical Services segment accounted for 11% of total consolidated revenues for the three months ended June 30, 2006 and 2005, and 11% and 12% for the six months ended June 30, 2006 and 2005, respectively. Revenues from the sale and marketing of natural gas using onshore assets accounted for 8% and 9% of total consolidated revenues for the three months ended June 30, 2006 and 2005, and 9% and 8% for the six months ended June 30, 2006 and 2005, respectively.

13. Related Party Transactions

          The following table summarizes our related party transactions for the periods indicated:

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005
Revenues from consolidated operations
EPCO and affiliates	$	33,448	$	2	$	39,080	$	286
Unconsolidated affiliates		79,986		80,946		164,429		138,855
Total	$	113,434	$	80,948	$	203,509	$	139,141
Operating costs and expenses
EPCO and affiliates	$	71,105	$	64,991	$	166,062	$	123,994
Unconsolidated affiliates		7,904		3,898		14,590		10,466
Total	$	79,009	$	68,889	$	180,652	$	134,460
General and administrative expenses
EPCO and affiliates	$	10,830	$	11,119	$	21,838	$	20,794

Relationship with EPCO and affiliates

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

§	EPCO and its private company subsidiaries;
§	Enterprise Products GP, our sole general partner;
§	Enterprise GP Holdings, which owns and controls our general partner;
§	the Employee Partnership; and
§	TEPPCO and its general partner (“TEPPCO GP”), which are controlled by affiliates of EPCO.

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

          EPCO is a private company controlled by Dan L. Duncan, who is also a director and Chairman of Enterprise Products GP, our general partner. At June 30, 2006, EPCO and its affiliates beneficially owned 144,384,693 (or 34.5%) of our outstanding common units. In addition, at June 30, 2006, EPCO and its affiliates owned 86.7% of Enterprise GP Holdings, including 100% of EPE Holdings.

          The principal business activity of Enterprise Products GP is to act as our managing partner. The executive officers and certain of the directors of Enterprise Products GP and EPE Holdings are employees of EPCO.

          In connection with its general partner interest in us, Enterprise Products GP received cash distributions of $47.3 million and $35.3 million from us during the six months ended June 30, 2006 and 2005, respectively. These amounts include $40.1 million and $29.1 million of incentive distributions for

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the six months ended June 30, 2006 and 2005, respectively. Enterprise GP Holdings owns all of the membership interests of Enterprise Products GP.

          We and Enterprise Products GP 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 depends on the cash distributions it receives from us, Enterprise GP Holdings and other investments to fund its other operations and to meet its debt obligations. EPCO and its affiliates received $148.3 million and $117.8 million in cash distributions from us during the six months ended June 30, 2006 and 2005, respectively, in connection with its limited and general partner interests in us.

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

          We have entered into an agreement with an affiliate of EPCO to provide trucking services to us for the transportation of NGLs and other products. We also lease office space in various buildings from affiliates of EPCO. The rental rates in these lease agreements approximate market rates. In addition, we buy and sell NGL products to and from a foreign affiliate of EPCO at market-related prices in the normal course of business.

          Relationship with TEPPCO. We received $11.5 million and $17 million from TEPPCO during the three and six months ended June 30, 2006, respectively, from the sale of hydrocarbon products. During the three months ended June 30, 2006 and 2005, we paid TEPPCO $6.2 million and $7.1 million, respectively, for NGL pipeline transportation and storage services. We paid TEPPCO $10.6 million and $8.6 million for NGL pipeline transportation and storage services during the six months ended June 30, 2006 and 2005, respectively.

          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 transaction was reviewed and approved by the Audit and Conflicts Committee of the board of directors of our general partner and the general partner of TEPPCO, and a fairness opinion was rendered by an independent third-party. TEPPCO will have no continued involvement in the contracts or in the operations of the Pioneer facility. In addition, the unaudited pro forma financial impact of this transaction is not significant.

          In August 2006, we announced a joint venture in which we and TEPPCO will be partners in TEPPCO’s Jonah Gas Gathering Company. The Jonah Gas Gathering Company owns the Jonah Gas Gathering System (“the Jonah system”), located in the Greater Green River Basin of southwestern Wyoming, which gathers and transports natural gas produced from the Jonah and Pinedale fields to natural gas processing plants and major interstate pipelines that deliver natural gas to end-use markets.

          A letter of intent executed by us and TEPPCO in February 2006 provided that we would manage the construction and fund the initial capital cost of the Phase V expansion of the Jonah system. In connection with the joint venture arrangement, we and TEPPCO intend to continue the Phase V expansion, which is expected to increase the system capacity of the Jonah system from 1.5 Bcf/d to 2.4 Bcf/d and to significantly reduce system operating pressures, which is anticipated to lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which is believed to increase the system gathering capacity to 2 Bcf/d, is projected to be completed in the first quarter of 2007 at an estimated cost of approximately $275 million. The second portion of the expansion is expected to cost approximately $140 million and be completed by the end of 2007.

          We will manage the Phase V construction project, and in the third quarter of 2006, TEPPCO will reimburse us for 50% of the Phase V capital cost incurred through August 1, 2006. After August 1, 2006,

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we and TEPPCO will equally share the capital costs of the Phase V expansion. Our ultimate ownership interest in Jonah Gas Gathering Company will be based on our share of the total cost of the Phase V expansion. Upon completion of the expansion project, we and TEPPCO are expected to own an approximate 20% and 80% interest, respectively, in Jonah Gas Gathering Company, with us serving as operator. Our expenditures associated with this project were $106.9 million during the six months ended June 30, 2006, of which $97.8 million has been paid to vendors. Other assets on our Unaudited Condensed Consolidated Balance Sheet at June 30, 2006 include the $106.9 million of expenditures related to this project.

          Administrative Services Agreement. We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement (“ASA”). We and our general partner, Enterprise GP Holdings and its general partner, and TEPPCO and its general partner, among other affiliates, are parties to the ASA. We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees.

Relationships with unconsolidated affiliates

          Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline and the purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell natural gas to Promix and process natural gas at VESCO.

14. Earnings per Unit

          Basic earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the weighted-average number of distribution-bearing units (excluding restricted units) outstanding during a period. Diluted earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the sum of (i) the weighted-average number of distribution-bearing units outstanding during a period (as used in determining basic earnings per unit); (ii) the weighted-average number of time-vested and performance-based restricted common units outstanding during a period; and (iii) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”).

          In a period of net operating losses, the restricted units and incremental option units are excluded from the calculation of diluted earnings per unit due to their antidilutive effect. The dilutive incremental option units are calculated in accordance with the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the end of each period are used to repurchase common units at an average market value during the period. The amount of common units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.

          The amount of net income or loss allocated to limited partner interests is net of our general partner’s share of such earnings. The following table shows the allocation of net income to our general partner for the periods indicated:

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2006			2005			2006			2005
Net income	$	126,295		$	70,659		$	260,072		$	179,915
Less incentive earnings allocations to Enterprise Products GP		(20,997	)		(15,516	)		(40,112	)		(29,136	)
Net income available after incentive earnings allocation		105,298			55,143			219,960			150,779
Multiplied by Enterprise Products GP ownership interest		2.0	%		2.0	%		2.0	%		2.0	%
Standard earnings allocation to Enterprise Products GP	$	2,106		$	1,103		$	4,399		$	3,016
Incentive earnings allocation to Enterprise Products GP	$	20,997		$	15,516		$	40,112		$	29,136
Standard earnings allocation to Enterprise Products GP		2,106			1,103			4,399			3,016
Enterprise Products GP interest in net income	$	23,103		$	16,619		$	44,511		$	32,152

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          The following table shows the calculation of our limited partners’ interest in net income and basic and diluted earnings per unit.

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2006			2005			2006			2005
Income before change in accounting principle and Enterprise Products GP interest	$	126,295		$	70,659		$	258,597		$	179,915
Cumulative effect of change in accounting principle								1,475
Net income		126,295			70,659			260,072			179,915
Enterprise Products GP interest in net income		(23,103	)		(16,619	)		(44,511	)		(32,152	)
Net income available to limited partners	$	103,192		$	54,040		$	215,561		$	147,763
BASIC EARNINGS PER UNIT
Numerator
Income before change in accounting principle and Enterprise Products GP interest	$	126,295		$	70,659		$	258,597		$	179,915
Cumulative effect of change in accounting principle								1,475
Enterprise Products GP interest in net income		(23,103	)		(16,619	)		(44,511	)		(32,152	)
Limited partners’ interest in net income	$	103,192		$	54,040		$	215,561		$	147,763
Denominator
Common units		408,275			383,734			401,820			378,376
Basic earnings per unit
Income per unit before change in accounting principle and Enterprise Products GP interest	$	0.31		$	0.18		$	0.64		$	0.47
Cumulative effect of change in accounting principle								0.01
Enterprise Products GP interest in net income		(0.06	)		(0.04	)		(0.11	)		(0.08	)
Limited partners’ interest in net income	$	0.25		$	0.14		$	0.54		$	0.39
DILUTED EARNINGS PER UNIT
Numerator
Income before change in accounting principle and Enterprise Products GP interest	$	126,295		$	70,659		$	258,597		$	179,915
Cumulative effect of change in accounting principle								1,475
Enterprise Products GP interest in net income		(23,103	)		(16,619	)		(44,511	)		(32,152	)
Limited partners’ interest in net income	$	103,192		$	54,040		$	215,561		$	147,763
Denominator
Common units		408,275			383,734			401,820			378,376
Time-vested restricted units		968			495			862			495
Performance-based restricted units		27			54			27			54
Incremental option units		234			526			241			612
Total		409,504			384,809			402,950			379,537
Diluted earnings per unit
Income per unit before change in accounting principle and Enterprise Products GP interest	$	0.31		$	0.18		$	0.64		$	0.47
Cumulative effect of change in accounting principle								0.01
Enterprise Products GP interest in net income		(0.06	)		(0.04	)		(0.11	)		(0.08	)
Limited partners’ interest in net income	$	0.25		$	0.14		$	0.54		$	0.39

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15. Commitments and Contingencies

Litigation

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

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

          We acquired additional ownership interests in our octane-additive production facility from affiliates of Devon Energy Corporation (“Devon”), which sold us its 33.3% interest in 2003, and Sunoco, Inc. (“Sun”), which sold us its 33.3% interest in 2004. As a result of these acquisitions, we own 100% of our Mont Belvieu, Texas octane-additive production facility. Devon and Sun have indemnified us for any liabilities (including potential liabilities as described in the preceding paragraph) that are in respect of periods prior to the date we purchased such interests. There are no dollar limits or deductibles associated with the indemnities we received from Sun and Devon with respect to potential claims linked to the period of time they held ownership interests in our octane-additive production facility.

Operating leases

          We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, and (iii) land held pursuant to right-of-way agreements. In general, our material lease agreements have original terms that range from 14 to 20 years and include renewal options that could extend the agreements for up to an additional 20 years. Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. Lease and rental expense included in operating income was $10 million and $8.9 million for the three months ended June 30, 2006 and 2005, respectively. For the six months ended June 30, 2006 and 2005, lease and rental expense included in operating income was $19.7 million and $18.2 million, respectively.

          There have been no material changes in our operating lease commitments since December 31, 2005, except for the renewal of our Wilson natural gas storage facility lease. During the first quarter of 2006, we exercised our right to renew the Wilson lease for an additional 20-year period. Our rental payments under the renewal agreement are at a fixed rate. Under the renewal agreement, we have the option to purchase the Wilson natural gas storage facility at either December 31, 2024 for $61 million or January 25, 2028 for $55 million. In addition, the lessor, at its election, may cause us to purchase the facility for $65 million at the end of any calendar quarter beginning on March 31, 2008 and extending through December 31, 2023. After adjusting for the renewal, the incremental future minimum lease payments associated with our lease of the Wilson natural gas storage facility are as follows: $4.1 million, 2008; $5.5 million, 2009; $5.5 million, 2010; and $94.9 million thereafter.

Performance guaranty

          In December 2004, a subsidiary of the Operating Partnership entered into the Independence Hub Agreement (the “Hub Agreement”) with six oil and natural gas producers. The Hub Agreement, as amended, obligates the subsidiary (i) to construct an offshore platform production facility to process 1

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Bcf/d of natural gas and condensate and (ii) to process certain natural gas and condensate production of the six producers following construction of the platform facility.

          In conjunction with the Hub Agreement, our Operating Partnership guaranteed the performance of its subsidiary under the Hub Agreement up to $426 million. In December 2004, 20% of this guaranteed amount was assumed by Helix Energy Solutions Group, Inc. (formerly known as Cal Dive International, Inc.), our joint venture partner in the Independence Hub project. The remaining $341 million represents our share of the anticipated construction cost of the platform facility. This amount represents the cap on our Operating Partnership’s potential obligation to the six producers for the cost of constructing the platform under the remote scenario where the six producers finish construction of the platform facility. This performance guarantee continues until the earlier to occur of (i) all of the guaranteed obligations of the subsidiary shall have been terminated, paid or otherwise discharged in full, (ii) upon mutual written consent of our Operating Partnership and the producers or (iii) mechanical completion of the production facility. We currently expect that mechanical completion of the platform will occur in January 2007; therefore, we anticipate that the performance guaranty will exist until at least this future period.

          In accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” we recorded the fair value of the performance guaranty using an expected present value approach. Given the remote probability that our Operating Partnership would be required to perform under this guaranty, we have estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of other current liabilities on our Unaudited Condensed Consolidated Balance Sheet at June 30, 2006.

16. Significant Risks and Uncertainties – Weather-Related Risks

          EPCO renewed its property and casualty insurance programs during the second quarter of 2006. As a result of severe hurricanes such as Katrina and Rita that occurred in 2005, market conditions for obtaining property damage insurance coverage were difficult. Under our renewed insurance programs, coverage is more restrictive including increased physical damage and business interruption deductibles. For example, our deductible for onshore physical damage increased from $2.5 million to $5 million per event and our deductible period for onshore business interruption claims increased from 30 days to 60 days. Additional restrictions will also be applied in the event of damage from named windstorms.

          In addition to changes in coverages, the cost of property damage insurance increased substantially from prior periods. At present, our annualized cost of insurance premiums for all lines of coverage is approximately $49.2 million, which represents a $28.1 million (or 133%) increase from our 2005 annualized insurance cost.

          The following is a discussion of the general status of insurance claims related to significant storm events that affected our assets in 2004 and 2005. To the extent we include estimates regarding the dollar value of damages, please be aware that a change in our estimates may occur as additional information becomes available to us.

          Hurricane Ivan insurance claims. Our final purchase price allocation related to the merger of GulfTerra with a wholly owned subsidiary of Enterprise Products Partners in September 2004 (the “GulfTerra Merger”) included a $26.2 million receivable for insurance claims related to expenditures to repair property damage to certain pre-merger GulfTerra assets caused by Hurricane Ivan. During the first quarter of 2006, we received cash reimbursements from insurance carriers totaling $24.1 million related to these property damage claims, and we expect to recover the remaining $2.1 million in late 2006. If the final recovery of funds is different than the amount previously expended, we will recognize an income impact at that time.

          In addition, we have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan. During the first quarter of 2006, we received claim proceeds of $10.2 million, and in April 2006 we received an additional $2 million. To the extent we receive cash proceeds from

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business interruption insurance claims, they are recorded as a gain in our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income in the period of receipt.

          Hurricanes Katrina and Rita insurance claims. Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. Inspection, evaluation and repair of property damage to our facilities is continuing. To the extent that insurance proceeds from property damage claims do not cover our estimated recoveries (in excess of the $5 million of insurance deductibles we expensed during the third quarter of 2005), such shortfall will be charged to earnings when realized. We recorded $63.5 million of estimated recoveries from property damage claims arising from Hurricanes Katrina and Rita, based on amounts expended through June 30, 2006. To the extent we receive cash proceeds from business interruption claims, they will be recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

17. Supplemental Cash Flow Information

          We prepare our Unaudited Condensed Statements of Consolidated Cash Flows using the indirect method. The indirect method derives net cash flows from operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in inventory, deferred income and the like, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, (iii) the effects of all items classified as investing or financing cash flows, such as gains or losses on sale of assets or gains or losses from the extinguishment of debt and (iv) other non-cash amounts such as depreciation, amortization and changes in the fair market value of instruments.

          The net effect of changes in operating assets and liabilities is as follows for the periods indicated:

	For the Six Months
	Ended June 30,
	2006			2005
Decrease (increase) in:
Accounts and notes receivable	$	117,826		$	65,688
Inventories		(111,631	)		(178,770	)
Prepaid and other current assets		(48,347	)		(19,510	)
Other assets		7,601			31,107
Increase (decrease) in:
Accounts payable		12,898			(114,170	)
Accrued gas payable		19,402			(48,553	)
Accrued expenses		35,911			(31,062	)
Accrued interest		(1,248	)		(574	)
Other current liabilities		45,843			712
Other long-term liabilities		(3,563	)		(1,141	)
Net effect of changes in operating accounts	$	74,692		$	(296,273	)

          Third parties may be obligated to reimburse us for all or a portion of project expenditures on certain of our capital projects. The majority of such arrangements are associated with projects related to pipeline construction projects and production well tie-ins. We received $34.9 million and $27 million as contributions in aid of our construction costs during the six months ended June 30, 2006 and 2005, respectively.

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18. Condensed Financial Information of Operating Partnership

          The Operating Partnership conducts substantially all of our business. Currently, we have no independent operations and no material assets outside those of our Operating Partnership.

          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. For additional information regarding our consolidated debt obligations, see Note 10.

          The reconciling items between our consolidated financial statements and those of our Operating Partnership are insignificant.

          The following table shows condensed consolidated balance sheet data for the Operating Partnership at the dates indicated:

	June 30,		December 31,
	2006		2005
ASSETS
Current assets	$	2,000,077	$	1,960,015
Property, plant and equipment, net		9,018,275		8,689,024
Investments in and advances to unconsolidated affiliates, net		464,605		471,921
Intangible assets, net		909,323		913,626
Goodwill		493,995		494,033
Deferred tax asset		3,444		3,606
Other assets		147,578		39,014
Total	$	13,037,297	$	12,571,239
LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	$	1,980,810	$	1,894,227
Long-term debt		4,821,401		4,833,781
Other long-term liabilities		131,201		84,486
Minority interest		124,497		106,159
Partners’ equity		5,979,388		5,652,586
Total	$	13,037,297	$	12,571,239
Total Operating Partnership debt obligations guaranteed by us	$	4,884,000	$	4,844,000

          The following table shows condensed consolidated statements of operations data for the Operating Partnership for the periods indicated:

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2006			2005			2006			2005
Revenues	$	3,517,853		$	2,671,768		$	6,767,927		$	5,227,290
Costs and expenses		3,339,326			2,548,221			6,397,972			4,945,867
Equity in income of unconsolidated affiliates		8,012			2,581			12,041			10,860
Operating income		186,539			126,128			381,996			292,283
Other income (expense)		(53,413	)		(55,741	)		(109,925	)		(108,216	)
Income before provision for income taxes, minority interest and change in accounting principle		133,126			70,387			272,071			184,067
Provision for income taxes		(6,272	)		1,034			(9,164	)		(735	)
Income before minority interest and change in accounting principle		126,854			71,421			262,907			183,332
Minority interest		(534	)		(392	)		(2,733	)		(2,333	)
Income before change in accounting principle		126,320			71,029			260,174			180,999
Cumulative effect of change in accounting principle								1,475
Net income	$	126,320		$	71,029		$	261,649		$	180,999

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19. Subsequent Events

          July 2006 Junior Notes Offering

          In July 2006, the Operating Partnership sold $300 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due 2066 (“Junior Notes A”). The Operating Partnership used the proceeds from issuing this subordinated debt to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. The Operating Partnership’s payment obligations under Junior Notes A are subordinated to all of its current and future senior indebtedness (as defined in the Indenture Agreement). Enterprise Products Partners has guaranteed repayment of amounts due under Junior Notes A through an unsecured and subordinated guarantee.

          The indenture agreement governing Junior Notes A allows the Operating Partnership to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. The indenture agreement also provides that, unless (i) all deferred interest on Junior Notes A has been paid in full as of the most recent interest payment date, (ii) no event of default under the Indenture has occurred and is continuing and (iii) Enterprise Products Partners is not in default of its obligations under related guarantee agreements, then the Operating Partnership and Enterprise Products Partners cannot declare or make any distributions with respect to any of their respective equity securities or make any payments on indebtedness or other obligations that rank pari passu with or subordinate to Junior Notes A.

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

          In connection with the issuance of Junior Notes A, the Operating Partnership entered into a Replacement Capital Covenant in favor of the covered debtholders (as named therein) pursuant to which the Operating Partnership agreed for the benefit of such debtholders that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made from the proceeds of issuance of certain securities.

          July 2006 Acquisition of Natural Gas Gathering Assets in South Texas

          In July 2006, we acquired certain natural gas gathering systems and related gathering and processing contracts from Cerrito Gathering Company, Ltd. (“Cerrito”), an affiliate of Lewis Energy Group, L.P. (“Lewis”). The total consideration paid by us was $325 million, which consisted of approximately $146 million in cash and the issuance of approximately 7.1 million of our common units.

          The Cerrito gathering systems are located in South Texas and are connected to over 1,450 wells having an aggregate production volume of over 100 MMcf/d of natural gas sourced from the Olmos and Wilcox Trends in South Texas. The Cerrito gathering systems consist of 484 miles of pipeline, comprised of 312 miles of pipeline we acquired from Lewis in this transaction and 172 miles of pipeline that we own and had previously leased to Lewis. The Cerrito gathering system is supported by 31,000 horsepower of compression. Volumes currently gathered by the Cerrito systems are delivered into our South Texas gas processing and pipeline transportation system.

          These gathering systems will be supported by a long-term dedication by Lewis of its production from the Olmos formation. In addition to the natural gas gathering and processing dedication, the transaction also includes a long-term dedication to transport lean gas gathered and treated at Lewis’ Big Reef Treating facility. The Big Reef facility will gather and treat sour gas production from the southern portion of the Edwards Trend in South Texas.

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          August 2006 Purchase of NGL Pipeline

          In August 2006, we purchased 226 miles of NGL pipelines extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The total purchase price for these assets was $97.9 million in cash. We funded this asset purchase using borrowings under our Multi-Year Revolving Credit Facility. This pipeline will be used to transport mixed NGLs from our South Texas natural gas processing plants to our Mont Belvieu fractionation facilities.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

For the three and six months ended June 30, 2006 and 2005.

          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 are a North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, natural gas liquids (“NGLs”), crude oil and certain petrochemicals. In addition, we are an industry leader in the development of pipeline and other midstream energy infrastructure in the continental United States and Gulf of Mexico. 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.” We, Enterprise Products GP and Enterprise GP Holdings are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO, Inc. (“EPCO”).

          This quarterly report contains various forward-looking statements and information based on our beliefs and those of Enterprise Products GP, our general partner, as well as assumptions made by us and information currently available to us. Please read the section titled “Cautionary Statement Regarding Forward-Looking Information” included within this Item 2.

          As generally used in the energy industry and in this document, the terms listed below have the following meanings:

/d	= per day
BBtus	= billion British thermal units
Bcf	= billion cubic feet
MBPD	= thousand barrels per day
Mdth	= thousand dekatherms
MMBbls	= million barrels
MMBtus	= million British thermal units
MMcf	= million cubic feet
Mcf	= thousand cubic feet
TBtu	= trillion British thermal units

          In addition, 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.

          The following discussion and analysis should be read in conjunction with our unaudited condensed consolidated financial statements and notes included under Item 1 of this quarterly report on Form 10-Q and with the information contained within our annual report on Form 10-K for the year ended December 31, 2005 (Commission File No. 1-14323).

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RECENT DEVELOPMENTS

          In general, our outlook for 2006 remains the same as that discussed in our annual report on Form 10-K for 2005. The following summarizes our significant developments since December 31, 2005 through the date of this filing.

§	In March 2006, we sold 18,400,000 of our common units in a public offering (including the over-allotment amount of 2,400,000 common units), which generated net proceeds of approximately $430 million.
§	In March 2006, we announced plans to expand our petrochemical assets located in southeast Texas at an expected cost of $205 million. The plans include the construction of a new propylene fractionator at our Mont Belvieu, Texas facility and the expansion of two refinery grade propylene pipelines. These additions are expected to be complete in late 2007.
§	In March 2006, we purchased the Pioneer natural gas processing plant and certain natural gas processing rights from TEPPCO for $38.1 million in cash.
§	In April 2006, we announced plans to expand our Houston Ship Channel NGL import and export facility and related pipeline and other assets to accommodate an expected increase in throughput volumes. This expansion project is expected to cost $40 million and be completed in the second quarter of 2007.
§	In July 2006, the Operating Partnership sold $300 million in principal amount of fixed/floating unsecured junior subordinated notes. For additional information regarding this issuance of debt, please read “Liquidity and Capital Resources” included within this Item 2.
§	In July 2006, we acquired natural gas gathering systems and related gathering and processing contracts from Cerrito Gathering Company, Ltd. (“Cerrito”), an affiliate of Lewis Energy Group L.P. (“Lewis”). The total consideration paid by us was $325 million, which consisted of approximately $146 million in cash and the issuance of approximately 7.1 million of our common units.
§	In July 2006, we signed long-term agreements with CenterPoint Energy Resources Corp. (“CenterPoint Energy”) to provide firm natural gas transportation and storage services to its natural gas utility, primarily in the Houston metropolitan area.
§	In August 2006, we purchased 226 miles of NGL pipelines extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil Pipeline Company (“ExxonMobil”). The total purchase price for these assets was $97.9 million in cash.

          For additional information regarding our capital spending and acquisitions, please read “Capital Spending” included within this Item 2.

CAPITAL SPENDING

          We are committed to the long-term growth and viability of Enterprise Products Partners. Part of our business strategy involves expansion through business combinations, growth capital projects and investments in joint ventures. We believe that we are positioned to continue to grow our system of assets through the construction of new facilities and to capitalize on expected future production increases from such areas as the Piceance Basin of western Colorado, the Greater Green River Basin in Wyoming, and the deepwater Gulf of Mexico.

          Management continues to analyze potential acquisitions, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions. In recent years, major oil and gas companies have sold non-strategic assets in the midstream energy sector in which we operate. We

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forecast that this trend will continue, and expect independent oil and natural gas companies to consider similar divestitures.

          Based on information currently available, we estimate our consolidated capital spending during 2006 will approximate $2.1 billion, of which $0.6 billion was spent during the first six months of 2006. Of the remaining $1.5 billion forecast to be spent during the third and fourth quarters of 2006, $1.4 billion is attributable to growth capital projects and acquisitions. The $1.4 billion includes the $325 million of consideration we paid or issued to Lewis in July 2006 to acquire natural gas gathering assets located in South Texas and the $100 million we paid to ExxonMobil in August 2006 to acquire NGL pipelines.

          Our forecast of consolidated capital expenditures is based on our strategic operating and growth plans, which are dependent upon our ability to generate the required funds from either operating cash flows or from other means, including borrowings under debt agreement and potential divestitures of assets to third and/or related parties. Our forecast of capital expenditures may change due to factors beyond our control, such as weather related issues, changes in supplier prices or adverse economic conditions. Furthermore, our forecast may change as a result of decisions made by management at a later date, which may include acquisitions or decisions to take on additional partners.

          Our success in raising capital, including the formation of joint ventures to share costs and risks, continues to be the principal factor that determines how much we can spend. We believe our access to capital resources is sufficient to meet the demands of our current and future operating growth needs, and although we currently intend to make the forecasted expenditures discussed above, we may adjust the timing and amounts of projected expenditures in response to changes in capital markets.

          The following table summarizes our capital spending by activity for the periods indicated (dollars in thousands):

	For the Six Months
	Ended June 30,
	2006		2005
Capital spending for business combinations and asset purchases:
Pioneer natural gas processing plant and associated processing rights purchased from TEPPCO	$	38,100
Indirect interests in the Indian Springs natural gas gathering and processing assets			$	74,854
Additional ownership interests in Dixie Pipeline Company (“Dixie”)				68,608
Additional ownership interests in Mid-America and Seminole pipeline systems				25,000
Other business combinations				12,617
Total		38,100		181,079
Capital spending for property, plant and equipment:
Growth capital projects		475,947		371,894
Sustaining capital projects		64,531		36,843
Total		540,478		408,737
Capital spending attributable to unconsolidated affiliates:
Investments in and advances to unconsolidated affiliates		6,995		81,780
Advances to Jonah affiliate		97,767
Total capital spending	$	683,340	$	671,596

          Our capital spending for growth capital projects (as presented in the preceding table) are net of amounts we received from third parties as contributions in aid of our construction costs. Such contributions were $34.9 million and $27 million for the six months ended June 30, 2006 and 2005, respectively. On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with projects related to pipeline construction projects and production well tie-ins.

          At June 30, 2006, we had $200.9 million in outstanding purchase commitments, which primarily relate to growth capital projects in the Rocky Mountains and offshore Gulf of Mexico that are expected to be placed in service in 2006 and 2007.

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Significant Recently Announced Growth Capital Projects

          The following summarizes our significant growth capital projects initiated since December 31, 2005 through the date of this filing.

          Piceance Basin Gas Processing Project. In January 2006, we announced the execution of a minimum 15-year natural gas processing agreement with an affiliate of the EnCana Corporation (“EnCana”). Under that agreement, we will have the right to process up to 1.3 Bcf/d of EnCana’s natural gas production from the Piceance Basin area of western Colorado. To accommodate this production, we have begun construction of the Meeker natural gas processing facility in Rio Blanco County, Colorado. In addition, we will construct an approximate 50-mile NGL pipeline that will connect our Meeker facility with our Mid-America Pipeline System. The Meeker natural gas processing plant, which will provide us with 750 MMcf/d of natural gas processing capacity and the ability to recover up to 35 MBPD of NGLs, is expected to be placed in service in mid-2007 at a cost of $285 million. We are currently working to secure production dedications from additional producers. In June 2006, EnCana executed an option which requires us to build an expansion of the Meeker facility by mid-2009. Under the terms of the agreement, EnCana has certain guaranteed payment obligations to us.

          Wyoming Gas Processing Projects. In January 2006, we announced our intent to purchase from an affiliate of TEPPCO the Pioneer natural gas processing plant located in Opal, Wyoming and the rights of TEPPCO and its affiliates to process natural gas originating from the Jonah and Pinedale fields in the Greater Green River Basin in Wyoming. We completed this acquisition in March 2006 at a cost of $38.1 million and commenced construction to increase the processing capacity of the Pioneer plant from 300 MMcf/d to 600 MMcf/d at an additional cost of $21 million. This expansion was completed in July 2006. This transaction was reviewed and approved by the Audit and Conflicts Committee of the board of directors of our general partner and the general partner of TEPPCO, and a fairness opinion was rendered by an independent third-party. TEPPCO will have no continued involvement in the contracts or in the operations of the Pioneer facility.

          In addition, to handle future production growth in the region, we started construction of a new natural gas processing plant in July 2006 having a capacity of 650 MMcf/d adjacent to the Pioneer plant. We expect our new natural gas processing plant to be placed in service by the third quarter of 2007 at an expected cost of $250 million.

          Phase V Jonah Expansion. In August 2006, we announced a joint venture in which we and TEPPCO will be partners in TEPPCO’s Jonah Gas Gathering Company. The Jonah Gas Gathering Company owns the Jonah Gas Gathering System (“the Jonah system”), located in the Greater Green River Basin of southwestern Wyoming, which gathers and transports natural gas produced from the Jonah and Pinedale fields to natural gas processing plants and major interstate pipelines that deliver natural gas to end-use markets.

          A letter of intent executed by us and TEPPCO in February 2006 provided that we would manage the construction and fund the initial capital cost of the Phase V expansion of the Jonah system. In connection with the joint venture arrangement, we and TEPPCO intend to continue the Phase V expansion, which is expected to increase the system capacity of the Jonah system from 1.5 Bcf/d to 2.4 Bcf/d and to significantly reduce system operating pressures, which is anticipated to lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which is believed to increase the system gathering capacity to 2 Bcf/d, is projected to be completed in the first quarter of 2007 at an estimated cost of approximately $275 million. The second portion of the expansion is expected to cost approximately $140 million and be completed by the end of 2007.

          We will manage the Phase V construction project, and in the third quarter of 2006, TEPPCO will reimburse us for 50% of the Phase V capital cost incurred through August 1, 2006. After August 1, 2006, we and TEPPCO will equally share the capital costs of the Phase V expansion. Our ultimate ownership interest in Jonah Gas Gathering Company will be based on our share of the total cost of the Phase V expansion. Upon completion of the expansion project, we and TEPPCO are expected to own an

39

approximate 20% and 80% interest, respectively, in Jonah Gas Gathering Company, with us serving as operator.

          Our expenditures associated with this project were $106.9 million during the six months ended June 30, 2006, of which $97.8 million has been paid to vendors.

          Expansion of Mont Belvieu Petrochemical Assets. In March 2006, we announced an expansion of petrochemical assets in Mont Belvieu and southeast Texas. This expansion project includes (i) the construction of a new propylene fractionator at our Mont Belvieu complex, which will increase our propylene/propane fractionation capacity by approximately 15 MBPD and (ii) the expansion of two refinery grade propylene gathering pipelines which will add 50 MBPD of gathering capacity into Mont Belvieu. These projects are expected to be operational by late 2007 and are expected to cost $205 million.

          Expansion of Houston Ship Channel Import and Export Facility. In April 2006, we announced an expansion of our NGL import and export terminal located on the Houston Ship Channel. This expansion project will increase offloading capability of our import facility from a maximum peak operating rate of 240 MBPD to 480 MBPD and the maximum loading rate of our export facility from 140 MBPD to 160 MBPD. As part of this expansion project, we will increase the transportation and processing capacities of certain of our assets that serve the terminal in order to accommodate the expected increase in import volumes. This expansion project is expected to cost $40 million and be completed in the second quarter of 2007.

          Purchase of Natural Gas Gathering Assets in South Texas. In July 2006, we acquired certain natural gas gathering systems and related gathering and processing contracts from Cerrito, an affiliate of Lewis. Total consideration paid by us was $325 million, comprised of approximately $146 million in cash and the issuance of approximately 7.1 million common units of Enterprise Products Partners.

          The Cerrito gathering systems are located in South Texas and are connected to over 1,450 wells having an aggregate production volume of over 100 MMcf/d of natural gas sourced from the Olmos and Wilcox Trends in South Texas. The Cerrito gathering systems consist of 484 miles of pipeline, comprised of 312 miles of pipeline we acquired from Lewis in this transaction and 172 miles of pipeline that we own and had previously leased to Lewis. The Cerrito gathering system is supported by 31,000 horsepower of compression. Volumes currently gathered by the Cerrito systems are delivered into our South Texas gas processing and pipeline transportation system.

          These gathering systems will be supported by a long-term dedication by Lewis of its production from the Olmos formation. In addition to the natural gas gathering and processing dedication, the transaction also includes a long-term dedication to transport lean gas gathered and treated at Lewis’ Big Reef Treating facility. The Big Reef facility will gather and treat sour gas production from the southern portion of the Edwards Trend in South Texas.

          Purchase of NGL Pipeline. In August 2006, we purchased 226 miles of NGL pipelines extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil. The total purchase price for these assets was $97.9 million in cash. This pipeline will be used to transport mixed NGLs from our South Texas natural gas processing plants to our Mont Belvieu fractionation facilities.

          Mid-America Pipeline System – Skellytown to Conway Addition. In June 2005, we began engineering and design work to construct a 190-mile, 12-inch NGL pipeline that will have the capacity to move up to 67 MBPD of mixed NGLs bi-directionally between Skellytown, Texas and Conway, Kansas and an additional 48 MBPD from Skellytown, Texas to Hobbs, New Mexico. Construction of this pipeline began in the spring of 2006 and is expected to cost $90 million and be placed in service by March 2007.

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Pipeline Integrity Costs

          Our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs administered by the U.S. Department of Transportation, through its Office of Pipeline Safety. During the three months ended June 30, 2006, we spent approximately $13.1 million to comply with these programs, of which $8.4 million was recorded as an operating expense and the remaining $4.7 million was capitalized. We spent approximately $31.6 million to comply with these programs during the six months ended June 30, 2006 of which $14.3 million was recorded as an operating expense and the remaining $17.3 million was capitalized.

          We expect our net cash outlay for pipeline integrity program expenditures to approximate $37.4 million for the remainder 2006. Our forecast is net of certain costs we expect to recover from El Paso in connection with an indemnification agreement. In May 2006, we recovered $13.7 million from El Paso related to our 2005 expenditures and expect to recover $9.7 million related to our first and second quarter 2006 expenditures, which leaves a remainder of $26.8 million reimbursable by El Paso for 2006 and 2007 pipeline integrity costs.

RESULTS OF OPERATIONS

          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-generally accepted accounting principle (“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 financial measure calculated using accounting principles generally accepted in the United States of America (“GAAP”) 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.

          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.

          For additional information regarding our business segments, please read Note 12 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

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Selected Price and Volumetric Data

          The following table presents selected average quarterly industry index prices for natural gas, crude oil and selected NGL and petrochemical products since the beginning of 2005:

															Polymer		Refinery
	Natural								Normal				Natural		Grade		Grade
	Gas,		Crude Oil,		Ethane,		Propane,		Butane,		Isobutane,		Gasoline,		Propylene,		Propylene,
	$/MMBtu		$/barrel		$/gallon		$/gallon		$/gallon		$/gallon		$/gallon		$/pound		$/pound
	(1)		(2)		(1)		(1)		(1)		(1)		(1)		(1)		(1)
2005
1st Quarter	$	6.27	$	49.68	$	0.52	$	0.79	$	0.98	$	1.00	$	1.14	$	0.45	$	0.39
2nd Quarter	$	6.74	$	53.09	$	0.52	$	0.82	$	0.98	$	1.01	$	1.16	$	0.37	$	0.30
3rd Quarter	$	8.53	$	63.08	$	0.69	$	0.97	$	1.14	$	1.26	$	1.36	$	0.37	$	0.33
4th Quarter	$	13.00	$	60.03	$	0.76	$	1.06	$	1.27	$	1.34	$	1.36	$	0.50	$	0.44
Average for Year	$	8.64	$	56.47	$	0.62	$	0.91	$	1.09	$	1.15	$	1.26	$	0.42	$	0.37
2006
1st Quarter	$	9.01	$	63.35	$	0.57	$	0.94	$	1.20	$	1.27	$	1.38	$	0.45	$	0.40
2nd Quarter	$	6.80	$	70.53	$	0.68	$	1.05	$	1.22	$	1.26	$	1.52	$	0.50	$	0.44
Average for Year	$	7.91	$	66.94	$	0.63	$	1.00	$	1.21	$	1.27	$	1.45	$	0.48	$	0.42

(1)

Natural gas, NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including Oil Price Information Service (“OPIS”) and Chemical Market Associates, Inc. (“CMAI”). The natural gas price is representative of Henry-Hub I-FERC. NGL prices are representative of Mont Belvieu Non-TET pricing. Refinery grade propylene represents an average of CMAI spot prices. Polymer-grade propylene represents average CMAI contract pricing.

(2)

Crude oil price is representative of an index price for West Texas Intermediate.

          The following table presents our significant average throughput, production and processing volumetric data. These statistics are reported on a net basis, taking into account our ownership interests, and reflect the periods in which we owned an interest in such operations.

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005
NGL Pipelines & Services, net:
NGL transportation volumes (MBPD)		1,559		1,511		1,490		1,461
NGL fractionation volumes (MBPD)		308		327		282		332
Equity NGL production (MBPD) (1)		61		84		59		84
Fee-based natural gas processing (MMcf/d)		2,465		2,001		2,138		2,009
Onshore Natural Gas Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)		5,907		5,985		5,979		5,866
Offshore Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)		1,523		2,156		1,500		2,004
Crude oil transportation volumes (MBPD)		161		151		137		139
Platform gas treating (Mcf/d)		158		319		158		317
Platform oil treating (MBPD)		18		7		12		8
Petrochemical Services, net:
Butane isomerization volumes (MBPD)		83		84		84		75
Propylene fractionation volumes (MBPD)		56		56		54		55
Octane additive production volumes (MBPD)		9		8		7		4
Petrochemical transportation volumes (MBPD)		93		72		90		73
Total, net:
NGL, crude oil and petrochemical transportation volumes (MBPD)		1,813		1,734		1,717		1,673
Natural gas transportation volumes (BBtus/d)		7,430		8,141		7,479		7,870
Equivalent transportation volumes (MBPD) (2)		3,768		3,877		3,685		3,744

(1)	Volumes for the first and second quarters of 2005 have been revised to incorporate asset-level definitions of equity NGL production volumes.
(2)	Reflects equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent to one barrel of NGLs.

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Comparison of Results of Operations

          The following table summarizes the key components of our results of operations for the periods indicated (dollars in thousands):

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005
Revenues	$	3,517,853	$	2,671,768	$	6,767,927	$	5,227,290
Operating costs and expenses		3,323,585		2,530,133		6,370,448		4,913,777
General and administrative costs		16,235		18,710		29,975		33,403
Equity in income of unconsolidated affiliates		8,012		2,581		12,041		10,860
Operating income		186,045		125,506		379,545		290,970
Interest expense		56,333		56,746		114,410		110,159
Net income		126,295		70,659		260,072		179,915

          Revenues from the sale and marketing of NGL products within the NGL Pipelines & Services business segment accounted for 69% and 66% of total consolidated revenues for the three months ended June 30, 2006 and 2005, and 68% and 66% for the six months ended June 30, 2006 and 2005, respectively. Revenues from the sale and marketing of petrochemical products within the Petrochemical Services segment accounted for 11% of total consolidated revenues for the three months ended June 30, 2006 and 2005, and 11% and 12% for the six months ended June 30, 2006 and 2005, respectively. Revenues from the sale and marketing of natural gas using onshore assets accounted for 8% and 9% of total consolidated revenues for the three months ended June 30, 2006 and 2005, and 9% and 8% for the six months ended June 30, 2006 and 2005, respectively.

          Our gross operating margin by segment and in total is as follows for the periods indicated (dollars in thousands):

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005
Gross operating margin by segment:
NGL Pipelines & Services	$	146,414	$	120,328	$	317,364	$	273,632
Onshore Natural Gas Pipelines & Services		86,651		84,903		183,454		164,261
Offshore Pipelines & Services		20,515		22,034		37,767		45,258
Petrochemical Services		57,044		18,610		84,562		37,938
Total segment gross operating margin	$	310,624	$	245,875	$	623,147	$	521,089

          For a reconciliation of non-GAAP gross operating margin to GAAP operating income and further to GAAP income before provision for taxes, minority interest and cumulative effect of change in accounting principle, please read “Other Items” included within this Item 2.

Comparison of Three Months Ended June 30, 2006 with
   Three Months Ended June 30, 2005

          Revenues for the second quarter of 2006 were $3.5 billion compared to $2.7 billion for the second quarter of 2005. The quarter-to-quarter increase in consolidated revenues is primarily due to higher sales volumes and energy commodity prices in the second quarter of 2006 relative to the same period in 2005. These differences accounted for an $820.6 million increase in consolidated revenues associated with our marketing activities.

          Operating costs and expenses were $3.3 billion for the second quarter of 2006 versus $2.5 billion for the second quarter of 2005. The quarter-to-quarter increase in consolidated operating costs and expenses is primarily due to an increase in the cost of sales associated with our marketing activities. The cost of sales of our natural gas, NGL and petrochemical products increased $754.4 million quarter-to-quarter as a result of higher energy commodity prices.

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          Changes in our revenues and costs and expenses period-to-period are explained in part by changes in energy commodity prices. The weighted-average indicative market price for NGLs was $1.04 per gallon during the second quarter of 2006 versus $0.81 per gallon during the second quarter of 2005—a quarter-to-quarter increase of 28%. Our determination of the weighted-average indicative market price for NGLs is based on U.S. Gulf Coast prices for such products at Mont Belvieu, Texas, which is the primary hub of the domestic NGL industry. The market price of natural gas (as measured at Henry Hub in Louisiana) averaged $6.80 per MMBtu during the second quarter of 2006 versus $6.74 per MMBtu during the second quarter of 2005. For additional historical energy commodity pricing information, please see the table on page 42.

          Equity earnings from unconsolidated affiliates were $8 million for the second quarter of 2006 compared to $2.6 million for the second quarter of 2005, an increase of $5.4 million quarter-to-quarter. Equity earnings for the second quarter of 2005 included a one-time charge of $11.5 million for costs associated with refinancing project finance debt of Cameron Highway Oil Pipeline Company (“Cameron Highway”), which was partially offset by a $5.1 million benefit associated with the settlement of a transportation contract dispute.

          Operating income for the second quarter of 2006 was $186 million compared to $125.5 million for the second quarter of 2005. Collectively, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to the $60.5 million increase in operating income quarter-to-quarter.

          Interest expense decreased $0.4 million quarter-to-quarter. Although outstanding debt balances and interest rates were higher during the second quarter of 2006 relative to the second quarter of 2005, significant amounts of interest are being capitalized as a result of borrowings to finance our capital spending program. Capitalized interest amounts were $12.4 million for the second quarter of 2006 compared to $3.2 million for the second quarter of 2005.

          Provision for income taxes increased $7.3 million quarter-to-quarter primarily due to the new Texas margin tax. For more information regarding the Texas margin tax, please see “Other Items” included within this Item 2.

          As a result of the items noted in previous paragraphs, our consolidated net income increased $55.6 million to $126.3 million for the second quarter of 2006 compared to $70.7 million for the second quarter of 2005.

          The following information highlights the significant quarter-to-quarter variances in gross operating margin by business segment:

          NGL Pipelines & Services. Gross operating margin from this business segment was $146.4 million for the second quarter of 2006 compared to $120.3 million for the second quarter of 2005. Improved results from our natural gas processing and related NGL marketing business accounted for substantially all of the $26.1 million increase in gross operating margin. Strong demand for NGLs in the second quarter of 2006 led to higher processing margins and increased volumes processed under fee-based contracts. Gross operating margin from our natural gas processing and related NGL marketing business was $80.8 million for the second quarter of 2006 compared to $55.7 million for the same quarter in 2005. Fee-based processing volumes increased to 2.5 Bcf/d during the second quarter of 2006 from 2 Bcf/d during the second quarter of 2005. Lastly, gross operating margin from natural gas processing for the second quarter of 2006 includes $2.3 million from the Pioneer plant we acquired from TEPPCO in March 2006.

          Gross operating margin from NGL pipelines and storage was $50.7 million for the second quarter of 2006 compared to $48.4 million for the second quarter of 2005. Total NGL transportation volumes increased to 1,559 MBPD during the second quarter of 2006 from 1,511 MBPD during the same quarter of 2005. The $2.3 million quarter-to-quarter increase in gross operating margin is attributable to higher NGL storage volumes and contributions from storage assets we acquired in July 2005. The increase in gross

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operating margin from our NGL storage business was partially offset by a $4.6 million increase in pipeline integrity costs quarter-to-quarter.

          Gross operating margin from NGL fractionation was $14.9 million for the second quarter of 2006 compared to $16.2 million for the second quarter of 2005. Fractionation volumes decreased from 327 MBPD during the second quarter of 2005 to 308 MBPD during the second quarter of 2006. The quarter-to-quarter decrease in gross operating margin and fractionation volumes is largely due to downtime and start-up costs associated with the completion of an expansion project at our Mont Belvieu NGL fractionator during the second quarter of 2006.

          Segment gross operating margin for the second quarter of 2006 also includes $2 million of income resulting from business interruption recoveries attributable to Hurricane Ivan. These recoveries relate to our South Louisiana assets that were affected by this storm in 2004.

          Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment was $86.7 million for the second quarter of 2006 compared to $84.9 million for the second quarter of 2005. Higher transportation revenues on our Texas Intrastate System contributed to a $4.6 million quarter-to-quarter increase in segment gross operating margin. An increase in drilling activity in the Permian and San Juan basins benefited our assets during the second quarter of 2006. Our gathering systems in the Permian basin experienced higher transportation volumes and natural gas sales margins quarter-to-quarter. As drilling activity increased, our San Juan Gas Gathering System started to benefit from its system optimization project, which was completed in early 2006. Collectively, gross operating margin from our San Juan and Permian basin gathering systems increased $3.2 million quarter-to-quarter. Segment gross operating margin for the second quarter of 2006 includes approximately $4 million of costs associated with the inspection, repair and maintenance of three storage caverns at our Wilson natural gas storage facility in Texas. Our total onshore natural gas transportation volumes were 5,907 BBtu/d during the second quarter of 2006 compared to 5,985 BBtu/d for the second quarter of 2005.

          We completed the expansion of our 30-inch West Texas pipeline system during the second quarter of 2006 and acquired the Cerrito natural gas gathering systems in July 2006. Our 30-inch West Texas pipeline system provides us 120 MMcf/d of incremental natural gas transportation capacity. This pipeline will transport production from the Barnett Shale and Permian basin areas to markets in Central Texas and the Gulf Coast. Our acquisition of the Cerrito natural gas gathering systems provides us, among other things, with life of lease dedications related to significant natural gas fields located in South Texas.

          Offshore Pipelines & Services. Gross operating margin from this business segment was $20.5 million for the second quarter of 2006 compared to $22 million for the second quarter of 2005. In general, offshore operations in the Gulf of Mexico continue to be impacted (albeit to a lesser degree at this time) by the lingering effects of last year’s hurricanes. Producers are working to restore production to at or near pre-hurricane levels and remain committed to exploration and production activities in the Gulf of Mexico, including its deepwater areas. As a result of industry losses last year, insurance costs for offshore operations have increased dramatically. Our insurance costs for these assets were $6 million for the second quarter of 2006 compared to $0.9 million for the second quarter of 2005.

          Gross operating margin from our offshore crude oil pipelines was a positive $5.8 million for the second quarter of 2006 versus a loss of $6.5 million for the second quarter of 2005. Our Marco Polo and Poseidon Oil Pipelines posted higher crude oil transportation volumes during the second quarter of 2006 due to increased production activity. Gross operating margin from the Marco Polo and Poseidon Oil Pipelines improved $2.1 million quarter-to-quarter. Our Constitution Oil Pipeline, which was placed in-service during the first quarter of 2006, contributed $2.5 million to segment gross operating margin during the second quarter of 2006. Gross operating margin from Cameron Highway improved $8.3 million quarter-to-quarter. Cameron Highway’s results for the second quarter of 2005 included a one-time charge of $11.5 million for costs associated with the refinancing of its project finance debt. Offshore crude oil transportation volumes were 161 MBPD during the second quarter of 2006 versus 151 MBPD during the second quarter of 2005.

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          Gross operating margin from our offshore natural gas pipelines was $6.5 million for the second quarter of 2006 compared to $17.3 million for the second quarter of 2005. Offshore natural gas transportation volumes were 1,523 BBtu/d during the second quarter of 2006 versus 2,156 BBtu/d during the second quarter of 2005. The decrease in gross operating margin and overall transportation volumes is primarily due to last year’s hurricanes. Also, gross operating margin attributable to this group of assets for the second quarter of 2005 includes a one-time $5.1 million benefit resulting from the settlement of a transportation contract dispute. Gross operating margin for the second quarter of 2006 includes $1.8 million from the Constitution Natural Gas Pipeline, which was placed in service during the first quarter of 2006.

          Our Phoenix Gas Gathering System returned to service during the second quarter of 2006 and is currently operating in excess of pre-hurricane rates. Volumes are expected to increase on our Viosca Knoll Gas Gathering System during the third quarter of 2006, as new production from the Matterhorn field is transported to processing facilities. Also, during the second quarter of 2006, we made significant progress on our Independence Hub and Trail project, which is scheduled for completion and first production during the first quarter of 2007.

          Gross operating margin from our offshore platforms was $8.2 million for the second quarter of 2006 compared to $11.2 million for the second quarter of 2005. The decrease in gross operating margin quarter-to-quarter is primarily due to last year’s hurricanes. Equity earnings from Deepwater Gateway, L.L.C., which owns the Marco Polo platform, increased $1.9 million quarter-to-quarter primarily due to higher processing volumes.

          Petrochemical Services. Gross operating margin from this business segment was $57 million for the second quarter of 2006 compared to $18.6 million for the second quarter of 2005. The $38.4 million quarter-to-quarter increase in gross operating margin is primarily due to improved results from our octane enhancement business. Gross operating margin from this business was a positive $20.5 million for the second quarter of 2006 compared to a loss of $6.1 million for the second quarter of 2005. The $26.6 million quarter-to-quarter increase is attributable to strong seasonal demand for isooctane as a motor gasoline additive. Isooctane, a high octane, low vapor pressure motor gasoline additive, complements the increasing use of ethanol, which has a high vapor pressure. Our isooctane production facility commenced operations in the second quarter of 2005.

          Gross operating margin from our propylene fractionation and pipeline activities was $16 million for the second quarter of 2006 versus $7.4 million for the second quarter of 2005. The quarter-to-quarter increase in gross operating margin of $8.6 million is primarily due to higher propylene sales margins and pipeline volumes. The second quarter of 2006 benefited from the use of a new pipeline, which we completed in 2005, that transports refinery-grade propylene from Texas City, Texas to our propylene fractionation complex at Mont Belvieu, Texas. Petrochemical transportation volumes were 93 MBPD during the second quarter of 2006 compared to 72 MBPD during the second quarter of 2005.

          Gross operating margin from butane isomerization was $20.5 million for the second quarter of 2006 compared to $17.3 million for the second quarter of 2005. The quarter-to-quarter increase of $3.2 million is primarily due to higher commodity sales prices.

Comparison of Six Months Ended June 30, 2006 with
   Six Months Ended June 30, 2005

          Revenues for the first six months of 2006 were $6.8 billion compared to $5.2 billion for the first six months of 2005. The period-to-period increase in consolidated revenues is primarily due to higher sales volumes and energy commodity prices during the first six months of 2006 relative to the 2005 period. These differences accounted for a $1.5 billion increase in consolidated revenues associated with our marketing activities.

          Operating costs and expenses were $6.4 billion for the first six months of 2006 compared to $4.9 billion for the first six months of 2005. The period-to-period increase in consolidated operating costs and

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expenses is primarily due to an increase in the costs of sales associated with our marketing activities. The cost of sales of our natural gas, NGL and petrochemical products increased $1.2 billion period-to-period as a result of higher energy commodity prices.

          Changes in our revenues and costs and expenses period-to-period are explained in part by changes in energy commodity prices. The weighted-average indicative market price for NGLs was $0.99 per gallon for the six months ended June 30, 2006 versus $0.80 per gallon during the first six months of 2005—a period-to-period increase of 24%. The Henry Hub market price for natural gas averaged $7.91 per MMBtu for the six months ended June 30, 2006 versus $6.51 per MMBtu during the 2005 period. For additional historical energy commodity pricing information, please see the table on page 42.

          Equity earnings from unconsolidated affiliates were $12 million for the first six months of 2006 versus $10.9 million for the first six months of 2005, an increase of $1.1 million period-to-period. Equity earnings for the first six months of 2005 include a one-time charge of $11.5 million for costs associated with the refinancing of Cameron Highway’s project finance debt, which was partially offset by a $5.1 million benefit associated with the settlement of a transportation contract dispute. Equity earnings from Venice Energy Services Company, LLC (“VESCO”) decreased $2 million period-to-period attributable to facility down-time and repair costs caused by the 2005 hurricanes.

          Interest expense increased to $114.4 million for the first six months of 2006 from $110.2 million for the first six months of 2005. Although outstanding debt balances and interest rates were higher during the first six months of 2006 relative to the 2005 period, significant amounts of interest are being capitalized as a result of borrowings to finance our capital spending program. Capitalized interest amounts were $21.6 million for the first six months of 2006 compared to $7.6 million for the first six months of 2005. Provision for income taxes increased $8.4 million period-to-period primarily due to the new Texas margin tax.

          As a result of the items noted in previous paragraphs, our consolidated net income increased $80.2 million to $260.1 million for the six months ended June 30, 2006 compared to $179.9 million for the 2005 period. The first six months of 2006 includes a $1.5 million benefit related to the cumulative effect of a change in accounting principle resulting from our adoption of Statement of Financial Accounting Standards (“SFAS”) 123(R) on January 1, 2006. For additional information regarding this cumulative effect adjustment, please read Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

          The following information highlights the significant period-to-period variances in gross operating margin by business segment:

          NGL Pipelines & Services. Gross operating margin from this business segment was $317.4 million for the first six months of 2006 compared to $273.6 million for the first six months of 2005. Improved results from our natural gas processing and related NGL marketing business and our NGL pipelines and storage business accounted for substantially all of the $43.8 million increase in gross operating margin. Strong demand for NGLs during 2006 led to higher processing margins and increased volumes processed under fee-based contracts. Gross operating margin from our natural gas processing and related NGL marketing business increased to $165.8 million for the first six months of 2006 from $139.3 million for the first six months of 2005. Fee-based processing volumes increased to 2.1 Bcf/d during the first six months of 2006 from 2 Bcf/d during the first six months of 2005. Lastly, gross operating margin from natural gas processing for the first six months of 2006 includes $2.3 million from the Pioneer plant we acquired from TEPPCO in March 2006.

          Gross operating margin from NGL pipelines and storage was $119.7 million for the first six months of 2006 compared to $100.4 million for the first six months of 2005. Total NGL transportation volumes increased to 1,490 MBPD for the first six months of 2006 from 1,461 MBPD for the first six months of 2005. The $19.3 million period-to-period increase in gross operating margin is attributable to higher pipeline transportation, NGL storage and export volumes at certain of our facilities and contributions from acquired or consolidated assets, particularly that generated by the Dixie NGL Pipeline. The increase

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in gross operating margin was partially offset by a $5.7 million increase in pipeline integrity costs period-to-period.

          Gross operating margin from NGL fractionation was $31.9 million for the first six months of 2006 compared to $33.8 million for the first six months of 2005. Fractionation volumes decreased from 332 MBPD during the first six months of 2005 to 282 MBPD during the first six months of 2006. The period-to-period decrease in gross operating margin and fractionation volumes is largely due to our Mont Belvieu and Norco NGL fractionators. Our Mont Belvieu NGL fractionator experienced downtime and start-up costs associated with the completion of its expansion project during the first six months of 2006. Our Norco NGL fractionator, which returned to normal operating rates in the second quarter of 2006, suffered a reduction of processing volumes due to the effects of Hurricane Katrina.

          Segment gross operating margin from this business segment for the 2006 period also includes $10.3 million of income resulting from business interruption recoveries attributable to Hurricane Ivan. These recoveries relate to our South Louisiana assets that were affected by this storm in 2004.

          Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment was $183.5 million for the first six months of 2006 compared to $164.3 million for the first six months of 2005. Higher transportation revenues on our Texas Intrastate System contributed to a $10.4 million increase in segment gross operating margin period-to-period. An increase in drilling activity in the Permian and San Juan basins benefited our assets during the first six months of 2006. Our gathering systems in the Permian basin experienced higher transportation volumes and natural gas sales margins period-to-period. Collectively, gross operating margin from our San Juan and Permian basin gathering systems increased $9.7 million period-to-period. Segment gross operating margin for the first six months of 2006 includes approximately $4 million of costs associated with the inspection, repair and maintenance of three storage caverns at our Wilson natural gas storage facility. Our total onshore natural gas transportation volumes were 5,979 BBtu/d during the first six months of 2006 compared to 5,866 BBtu/d during the first six months of 2005.

          Offshore Pipelines & Services. Gross operating margin from this business segment was $37.8 million for the first six months of 2006 compared to $45.3 million for the first six months of 2005. In general, offshore operations in the Gulf of Mexico continue to be impacted (albeit to a lesser degree at this time) by the lingering effects of last year’s hurricanes. As a result of industry losses last year, insurance costs for offshore operations have increased dramatically. Our insurance costs for the first six months of 2006 increased $5.2 million over those recorded during the first six months of 2005.

          Gross operating margin from our offshore crude oil pipelines was a positive $7.4 million for the first six months of 2006 versus a loss of $3.6 million for the first six months of 2005. Our Marco Polo Pipeline posted higher crude oil transportation volumes during the first six months of 2006 due to increased production activity. Gross operating margin from the Marco Polo Pipeline improved $2.1 million period-to-period. Our Constitution Oil Pipeline, which was placed in-service during the first quarter of 2006, contributed $3.4 million to segment gross operating margin during the first six months of 2006. Gross operating margin from Cameron Highway improved $7.1 million period-to-period. Cameron Highway’s results for the first six months of 2005 included a one-time charge of $11.5 million for costs associated with the refinancing of its project finance debt. Offshore crude oil transportation volumes were 137 MBPD during the first six months of 2006 versus 139 MBPD during the first six months of 2005.

          Gross operating margin from our offshore natural gas pipelines was $13.7 million for the first six months of 2006 compared to $27.5 million for the first six months of 2005. Offshore natural gas transportation volumes were 1,500 BBtu/d during the first six months of 2006 versus 2,004 BBtu/d during the first six months of 2005. The decrease in gross operating margin and overall transportation volumes is primarily due to last year’s hurricanes. Also, gross operating margin attributable to this group of assets for the first six months of 2005 includes a one-time $5.1 million benefit resulting from the settlement of a transportation contract dispute. Gross operating margin for the first six months of 2006 includes $2.1 million from the Constitution Natural Gas Pipeline, which was placed in service during the first quarter of 2006.

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          Gross operating margin from our offshore platforms and services business was $16.7 million for the first six months of 2006 compared to $21.4 million for the first six months of 2005. The decrease in gross operating margin period-to-period is primarily due to last year’s hurricanes. Equity earnings from Deepwater Gateway, L.L.C., which owns the Marco Polo platform, increased $3.5 million period-to-period primarily due to higher processing volumes.

          Petrochemical Services. Gross operating margin from this business segment was $84.6 million for the first six months of 2006 compared to $37.9 million for the first six months of 2005. The $46.7 million period-to-period increase in gross operating margin is primarily due to improved results from our octane enhancement business. Gross operating margin from this business was a positive $9.4 million for the first six months of 2006 compared to a loss of $15.1 million for the first six months of 2005. The $24.5 million period-to-period increase is attributable to strong seasonal demand for isooctane as a motor gasoline additive during the second quarter of 2006. Also, our isooctane production facility commenced operations in the second quarter of 2005.

          Gross operating margin from propylene fractionation was $36.5 million for the first six months of 2006 versus $22.2 million for the first six months of 2005. The period-to-period increase in gross operating margin of $14.3 million is primarily due to higher propylene sales margins and pipeline transportation volumes. Petrochemical transportation volumes were 90 MBPD during the first six months of 2006 compared to 73 MBPD during the first six months of 2005.

          Gross operating margin from butane isomerization was $38.6 million for the first six months of 2006 compared to $30.8 million for the first six months of 2005. The period-to-period increase of $7.8 million is largely due to increased demand for motor gasoline additives.

          Significant Risks and Uncertainties — Hurricanes

          The following is a discussion of the general status of insurance claims related to significant storm events that affected our assets in 2004 and 2005. To the extent we include estimates regarding the dollar value of damages, please be aware that a change in our estimates may occur as additional information becomes available to us.

          Hurricane Ivan insurance claims. Our final purchase price allocation related to the merger of GulfTerra with a wholly owned subsidiary of Enterprise Products Partners in September 2004 (the “GulfTerra Merger”) included a $26.2 million receivable for insurance claims related to expenditures to repair property damage to certain pre-merger GulfTerra assets caused by Hurricane Ivan. During the first quarter of 2006, we received cash reimbursements from insurance carriers totaling $24.1 million related to these property damage claims, and we expect to recover the remaining $2.1 million in late 2006. If the final recovery of funds is different than the amount previously expended, we will recognize an income impact at that time.

          In addition, we have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan. During the first quarter of 2006, we received claim proceeds of $10.2 million, and in April 2006 we received an additional $2 million. We expect to receive additional receipts of approximately $5.5 million during the third quarter of 2006. To the extent we receive cash proceeds from business interruption insurance claims, they are recorded as a gain in our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income in the period of receipt.

          Hurricanes Katrina and Rita insurance claims. Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. Inspection, evaluation and repair of property damage to our facilities is continuing. To the extent that insurance proceeds from property damage claims do not cover our estimated recoveries (in excess of the $5 million of insurance deductibles we expensed during the third quarter of 2005), such shortfall will be charged to earnings when realized. We recorded $63.5 million of estimated recoveries from property damage claims arising from Hurricanes Katrina and Rita, based on amounts expended through June 30, 2006. In July 2006, we received $1.2 million of physical damage proceeds, and we anticipate receiving an

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additional $9.3 million of physical damage proceeds in the third quarter of 2006. In July 2006, we received $4.9 million of business interruption proceeds, and we anticipate receiving an additional $41.6 million of business interruption proceeds during the third quarter of 2006. To the extent we receive cash proceeds from business interruption claims, they will be recorded as a gain in our statements of consolidated operations and comprehensive income in the period of receipt.

LIQUIDITY AND CAPITAL RESOURCES

          Our primary cash requirements, in addition to normal operating expenses and debt service, are for capital expenditures, business acquisitions and distributions to our partners. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows and short-term revolving credit arrangements. Capital expenditures for long-term needs resulting from internal growth projects and business acquisitions are expected to be funded by a variety of sources (either separately or in combination) including cash flows from operating activities, borrowings under commercial bank credit facilities and the issuance of additional equity and debt securities. We expect to fund cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.

          At June 30, 2006, we had $24.5 million of unrestricted cash on hand and approximately $673.4 million of available credit under our Operating Partnership’s Multi-Year Revolving Credit Facility. We had approximately $4.9 billion in principal outstanding under various consolidated debt obligations at June 30, 2006.

          As a result of our growth objectives, we expect to access debt and equity capital markets from time-to-time and we believe that financing arrangements to support our growth activities can be obtained on reasonable terms. Furthermore, we believe that maintenance of an investment grade credit rating combined with continued ready access to debt and equity capital at reasonable rates and sufficient trade credit to operate our businesses efficiently provide a solid foundation to meet our long and short-term liquidity and capital resource requirements.

          For additional information regarding our growth strategy, please read “Capital Spending” included within this Item 2.

Credit Ratings

          At July 31, 2006, the credit ratings of our Operating Partnership’s debt securities were Baa3 with a stable outlook as rated by Moody’s Investor Services; BBB- with a stable outlook as rated by Fitch Ratings; and BB+ with a positive outlook as rated by Standard and Poor’s.

          Based on the characteristics of the fixed/floating unsecured junior subordinated notes that the Operating Partnership issued in July 2006, the rating agencies assigned partial equity treatment to the notes. Moody’s Investor Services and Standard and Poor’s each assigned 50% equity treatment and Fitch Ratings assigned 75% equity treatment.

Registration Statements and Equity and Debt Offerings

          From time-to-time, we issue equity or debt securities to assist us in meeting our liquidity and capital spending requirements. We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (“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 $2.7 billion of additional securities under this registration statement as of July 31, 2006.

          In March 2006, we sold 18,400,000 common units (including an over-allotment amount of 2,400,000 common units) to the public at an offering price of $23.90 per unit. Net proceeds from this offering, including Enterprise Products GP’s proportionate net capital contribution of $8.6 million, were

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approximately $430 million after deducting applicable underwriting discounts, commissions and estimated offering expenses of $18.3 million. The net proceeds from this offering, including Enterprise Products GP’s proportionate net capital contribution, were used to temporarily reduce indebtedness outstanding under our Operating Partnership’s Multi-Year Revolving Credit Facility.

     In July 2006, the Operating Partnership sold $300 million in principal amount of fixed/floating unsecured junior subordinated notes (“Junior Notes A”). The Operating Partnership used the proceeds from this issuance to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. The Junior Notes A mature in August 2066 and will bear interest from July 2006 to August 2016 at an annual rate of 8.375%, and thereafter at an annual rate equal to the 3-month LIBOR rate for the related interest period plus 3.708%.

     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 “Capital Spending” included within this Item 2 for additional information regarding this acquisition.

Debt Obligations

     For detailed information regarding our consolidated debt obligations and those of our unconsolidated affiliates, please read Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report. The following table summarizes our consolidated debt obligations at the dates indicated (dollars in thousands):

	June 30,			December 31,
	2006			2005
Operating Partnership debt obligations:
Multi-Year Revolving Credit Facility, variable rate, due October 2011(1,2)	$	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(3)		(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)	We generated net proceeds of $430 million in March 2006 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.
(3)	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. For additional information regarding our fair value hedges, please read Item 3 of this quarterly report.

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          The following table summarizes the debt obligations of our unconsolidated affiliates (on a 100% basis to the joint venture) at June 30, 2006 and our ownership interest in each entity on that date (dollars in thousands):

	Our
	Ownership
	Interest			Total
Cameron Highway		50.0	%	$	415,000
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)		36.0	%		92,000
Evangeline Gas Pipeline Company, L.P.		49.5	%		30,650
Total				$	537,650

          In March 2006, Cameron Highway amended the note purchase agreement governing its senior secured notes to primarily address the effect of reduced deliveries of crude oil to Cameron Highway resulting from production delays caused by the lingering effects of Hurricanes Katrina and Rita. In general, this amendment modified certain financial covenants in light of production forecasts. In addition, the amendment increased 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.

          In May 2006, Poseidon amended its revolving credit facility, which, among other things, decreased the availability to $150 million from $170 million, extended the maturity date from January 2008 to May 2011 and lowered the borrowing rate.

Cash Flows from Operating, Investing and Financing Activities

          The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated (dollars in thousands). For information regarding the individual components of our cash flow amounts, please see the Unaudited Condensed Statements of Consolidated Cash Flows included under Item 1 of this quarterly report.

	For the Six Months
	Ended June 30,
	2006		2005
Net cash provided from operating activities	$	571,325	$	117,837
Net cash used in investing activities		689,787		570,449
Net cash provided by financing activities		100,888		461,101

          The following information highlights the significant quarter-to-quarter variances in our cash flow amounts:

          Comparison of Six Months Ended June 30, 2006 with Six Months Ended June 30, 2005

          Operating activities. Net cash provided from operating activities was $571.3 million for the first six months of 2006 compared to $117.8 million for the first six months of 2005. The $453.5 million period-to-period increase in net cash provided from operating activities is primarily due to:

§

Net income adjusted for all non-cash items and the net effects of changes in operating accounts increased $472 million period-to-period primarily due to the timing of cash receipts and payments during the periods.

§

Distributions received from unconsolidated affiliates decreased by $18.6 million period-to-period primarily due to (i) a decrease in distributions from VESCO resulting from facility down-time and repair costs in 2006 caused by damage inflicted by Hurricane Katrina, (ii) our receipt of a special distribution from Deepwater Gateway, L.L.C. (“Deepwater Gateway”) in March 2005 in connection with the repayment of its term loan and (iii) our receipt of a $5.1 million distribution

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from Neptune Pipeline Company, L.L.C. during 2005 associated with the resolution of a transportation contract dispute.

     Investing activities. Cash used in investing activities was $689.8 million for the first six months of 2006 compared to $570.4 million for the first six months of 2005. Expenditures for growth and sustaining capital projects (net of contributions in aid of construction costs) increased $131.7 million period-to-period primarily due to cash payments associated with our projects in the Rocky Mountains and Gulf of Mexico. In addition, during the first six months of 2006 we spent $97.8 million in connection with our Jonah expansion project. Our cash outlays for asset purchases and business combinations were $38.1 million for the first six months of 2006 versus $181.1 million for the first six months of 2005. For additional information related to our capital spending program, please read “Capital Spending” included within this Item 2.

     Our investments in unconsolidated affiliates decreased from $80.7 million for the first six months of 2005 to $14.1 million for the first six months of 2006. In March 2005, we contributed $72 million to Deepwater Gateway to fund our share of the repayment of its term loan.

     Cash inflows related to investing activities for the first six months of 2005 include cash receipts of (i) $42.1 million from the sale of our investment in Starfish Pipeline Company, LLC, which was required by the Federal Trade Commission in order to gain its approval for the GulfTerra Merger and (ii) $47.5 million related to a return of our investment in Cameron Highway associated with the refinancing of its project debt in June 2005.

     Financing activities. Cash provided by financing activities was $100.9 million for the first six months of 2006 compared to $461.1 million for the first six months of 2005. We had net borrowings under our debt agreements of $33 million during the first six months of 2006 versus $271.3 million during the first six months of 2005. We used $430 million of net proceeds from our March 2006 equity offering to reduce debt outstanding under our Operating Partnership’s Multi-Year Revolving Credit Facility. In addition, during 2006 we used borrowings under our Operating Partnership’s Multi-Year Revolving Credit Facility to fund our capital spending program.

     During the first six months of 2005, our Operating Partnership issued an aggregate of $1 billion in senior notes, the proceeds of which were used to repay $350 million due under its Senior Notes A, to temporarily reduce amounts outstanding under its other bank credit facilities and for general partnership purposes, including capital expenditures and business combinations. Also during the first six months of 2005, the Operating Partnership repaid $242.2 million then outstanding under its 364-Day Acquisition Credit Facility (which was used to finance elements of the GulfTerra Merger) using proceeds generated from our February 2005 equity offering.

     Net proceeds from the issuance of limited partner interests were $453.5 million for the first six months of 2006 compared to $525.2 million for the first six months of 2005. We issued 19,295,836 common units during the first six months of 2006 and 19,176,810 common units during the first six months of 2005. Net proceeds from underwritten equity offerings were $430 million during the first six months of 2006 reflecting the sale of 18,400,000 units and $456.7 million during the first six months of 2005 reflecting the sale of 17,250,000 units. We used net proceeds from these underwritten offerings to reduce debt, including the temporary repayment of indebtedness under bank credit facilities. Our distribution reinvestment program and related plan generated net proceeds of $21.9 million for the first six months of 2006 and $49.4 million for the first six months of 2005. We used net proceeds from these offerings for general partnership purposes.

     Cash distributions to partners increased from $346.6 million during the first six months of 2005 to $400.5 million during the first six months of 2006 primarily due to an increase in our common units outstanding and our quarterly cash distribution rates. Cash contributions from minority interests were $19 million for the first six months of 2006 compared to $23.6 million for the first six months of 2005. These amounts represent contributions from our joint venture partner in the Independence Hub project.

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CONTRACTUAL OBLIGATIONS

     Since December 31, 2005, scheduled maturities of long-term debt increased $33 million primarily due to borrowings under our Operating Partnership’s Multi-Year Revolving Credit Facility to fund our capital spending program, offset by the application of net proceeds generated by our equity offering in March 2006 to temporarily reduce debt outstanding under our Operating Partnership’s Multi-Year Revolving Credit Facility. For additional information regarding our debt obligations, please read Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report. Also, we renewed our lease of the Wilson natural gas storage facility for an additional 20-year period during the first quarter of 2006. For additional information regarding our commitments under this significant lease, please read Note 15 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

     Other than the items noted in the previous paragraph, there have been no significant changes with regard to our material contractual obligations (outside of the ordinary course of business) since those reported in our annual report on Form 10-K for the year ended December 31, 2005.

OFF-BALANCE SHEET ARRANGEMENTS

     In March 2006, Cameron Highway amended the note purchase agreement governing its senior secured notes to primarily address the effect of reduced deliveries of crude oil to Cameron Highway resulting from production delays caused by the lingering effects of Hurricanes Katrina and Rita. In general, this amendment modified certain financial covenants in light of production forecasts. In addition, the amendment increased the face amount of the letters of credit required to be issued by our Operating Partnership and an affiliate of our joint venture partner from $18.4 million each to $36.8 million each.

     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.

     Other than the amendments discussed above, there have been no significant changes with regard to our off-balance sheet arrangements since those reported in our annual report on Form 10-K for the year ended December 31, 2005.

RECENT ACCOUNTING DEVELOPMENTS

     In March 2006, we adopted the provisions of 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.

     In January 2007, we will adopt the provisions of 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.

     Also in January 2007, we will adopt 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

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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.

CRITICAL ACCOUNTING POLICIES

     In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect.

     In general, there have been no significant changes in our critical accounting policies since December 31, 2005. For a detailed discussion of these policies, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies” in our annual report on Form 10-K for 2005. The following describes the estimation risk underlying our most significant financial statement items:

Depreciation methods and estimated useful lives of property, plant and equipment

     In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts on a going forward basis.

     At June 30, 2006 and December 31, 2005, the net book value of our property, plant and equipment was $9 billion and $8.7 billion, respectively. For additional information regarding our property, plant and equipment, please read Note 6 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Measuring recoverability of long-lived assets and equity method investments

     In general, long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Equity method investments are evaluated for impairment whenever events or changes in circumstances indicate that there is a possible loss in value for the investment other than a temporary decline. Measuring the potential impairment of such assets and investments involves the estimation of future cash flows to be derived from the asset being tested. Our estimates of such cash flows are based on a number of assumptions including anticipated margins and volumes; estimated useful life of asset or asset group; and salvage values. A significant change in these underlying assumptions could result in our recording an impairment charge.

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Amortization methods and estimated useful lives of qualifying intangible assets

     In general, our intangible asset portfolio consists primarily of the estimated values assigned to certain customer relationships and customer contracts. We amortize the customer relationship values using methods that closely resemble the pattern in which the economic benefits of the underlying oil and natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. We amortize the customer contract intangible assets over the estimated remaining economic life of the underlying contract. A change in the estimates we use to determine amortization rates of our intangible assets (e.g., oil and natural gas production curves, remaining economic life of the contracts, etc.) could result in a material change in the amortization expense we record and the carrying value of our intangible assets.

     At June 30, 2006 and December 31, 2005, the carrying value of our intangible asset portfolio was $909.3 million and $913.6 million, respectively. For additional information regarding our intangible assets, please read Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Methods we employ to measure the fair value of goodwill

     Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values and is primarily comprised of $387.1 million associated with the GulfTerra Merger. We do not amortize goodwill; however, we test our goodwill (at the reporting unit level) for impairment during the second quarter of each fiscal year, and more frequently, if circumstances indicate it is more likely than not that the fair value of goodwill is below its carrying amount. Our goodwill testing involves the determination of a reporting unit’s fair value, which is predicated on our assumptions regarding the future economic prospects of the reporting unit. Our estimates of such prospects (i.e., cash flows) are based on a number of assumptions including anticipated margins and volumes of the underlying assets or asset group. A significant change in these underlying assumptions could result in our recording an impairment charge.

     At June 30, 2006 and December 31, 2005, the carrying value of our goodwill was $494 million. For additional information regarding our goodwill, please read Note 9 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Our revenue recognition policies and use of estimates for revenues and expenses

     Our use of certain estimates for revenues and operating costs and other expenses has increased as a result of SEC regulations that require us to submit financial information on accelerated time frames. Such estimates are necessary due to the timing of compiling actual billing information and receiving third-party data needed to record transactions for financial reporting purposes. If the basis of our estimates proves to be substantially incorrect, it could result in material adjustments in results of operations between periods.

Reserves for environmental matters

     Each of our business segments is subject to federal, state and local laws and regulations governing environmental quality and pollution control. Such laws and regulations may, in certain instances, require us to remediate current or former operating sites where specified substances have been released or disposed of. We accrue reserves for environmental matters when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Our assessments are based on studies, as well as site surveys, to determine the extent of any environmental damage and the necessary requirements to remediate this damage. Future environmental developments, such as increasingly strict environmental laws and additional claims for damages to property, employees and other persons resulting from current or past operations, could result in substantial additional costs beyond our current reserves.

     At June 30, 2006 and December 31, 2005, we had a liability for environmental remediation of $21 million, which was derived from a range of reasonable estimates based upon studies and site surveys. In

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accordance with SFAS 5 “Accounting for Contingencies” and Financial Accounting Standards Board Interpretation (“FIN”) 14, “Reasonable Estimation of the Amount of a Loss,” we recorded our best estimate of these remediation activities.

Natural gas imbalances

     Natural gas imbalances result when customers physically deliver a larger or smaller quantity of natural gas into our pipelines than they take out. In general, we value such imbalances using a twelve-month moving average of natural gas prices, which we believe is reasonable given that the actual settlement dates for such imbalances are generally not known. As a result, significant changes in natural gas prices between reporting periods may impact our estimates.

     At June 30, 2006 and December 31, 2005, our imbalance receivables were $77.9 million and $89.4 million, respectively, and are reflected as a component of accounts receivable. At June 30, 2006 and December 31, 2005, our imbalance payables were $58.2 million and $80.5 million, respectively, and are reflected as a component of accrued gas payables.

SUMMARY OF RELATED PARTY TRANSACTIONS

     In accordance with SFAS 57, “Related Party Disclosures,” we have identified our material related party revenues, costs and expenses. The following table summarizes our related party transactions for the periods indicated (dollars in thousands).

	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005
Revenues from consolidated operations
EPCO and affiliates	$	33,448	$	2	$	39,080	$	286
Unconsolidated affiliates		79,986		80,946		164,429		138,855
Total	$	113,434	$	80,948	$	203,509	$	139,141
Operating costs and expenses
EPCO and affiliates	$	71,105	$	64,991	$	166,062	$	123,994
Unconsolidated affiliates		7,904		3,898		14,590		10,466
Total	$	79,009	$	68,889	$	180,652	$	134,460
General and administrative expenses
EPCO and affiliates	$	10,830	$	11,119	$	21,838	$	20,794

     For additional information regarding our related party transactions identified in accordance with GAAP, please read Note 13 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

     We have an extensive and ongoing relationship with EPCO and its affiliates, including TEPPCO. Our revenues from EPCO and affiliates are primarily associated with sales of NGL products. Our expenses with EPCO and affiliates are primarily due to (i) reimbursements we pay EPCO in connection with an administrative services agreement and (ii) purchases of NGL products. TEPPCO is an affiliate of ours due to the common control relationship of both entities.

     Many of our unconsolidated affiliates perform supporting or complementary roles to our consolidated business operations. The majority of our revenues from unconsolidated affiliates relate to natural gas sales to a Louisiana affiliate. The majority of our expenses with unconsolidated affiliates pertain to payments we make to K/D/S Promix, LLC for NGL transportation, storage and fractionation services.

     At June 30, 2006, other assets includes $106.9 million related to our Jonah expansion project with TEPPCO. For additional information regarding the Jonah expansion project, please read “Capital Spending” included within this Item 2.

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OTHER ITEMS

Non-GAAP reconciliation

     The following table presents a reconciliation of total non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes, minority interest and the cumulative effect of a change in accounting principle (dollars in thousands):

	For the Three Months						For the Six Months
	Ended June 30,						Ended June 30,
	2006			2005			2006			2005
Total non-GAAP gross operating margin	$	310,624		$	245,875		$	623,147		$	521,089
Adjustments to reconcile total non-GAAP 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	)
GAAP consolidated operating income		186,045			125,506			379,545			290,970
Other expense		(52,940	)		(55,501	)		(109,048	)		(107,995	)
GAAP income before provision for income taxes, minority interest and cumulative effect of change in accounting principle	$	133,105		$	70,005		$	270,497		$	182,975

     EPCO subleases certain equipment located at our Mont Belvieu facility and 100 railcars for $1 per year (the “retained leases”) to us. These subleases are part of an administrative services agreement between EPCO and us that was executed in connection with our formation in 1998. EPCO holds this equipment pursuant to operating leases for which it has retained the corresponding cash lease payment obligation. We record the full value of such lease payments made by EPCO as a non-cash related party operating expense, with the offset to partners’ equity recorded as a general contribution to our partnership. Apart from the partnership interests we granted to EPCO at our formation, EPCO does not receive any additional ownership rights as a result of its contribution of the retained leases to us.

Cumulative effect of change in accounting principle

     Net income for the first quarter of 2006 includes a non-cash benefit of $1.5 million related to the cumulative effect of a change in accounting principle resulting from our adoption of SFAS 123(R) on January 1, 2006. For additional information regarding this cumulative effect adjustment, please read Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements included under Item 1 of this quarterly report.

Provision for income taxes — Texas Margin Tax

     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.

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     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.

     The constitutionality of the Texas Margin Tax is being questioned. The Texas Comptroller has requested a formal opinion from the Texas Attorney General on whether the Texas Margin Tax is an income tax that violates the Texas constitution. The Texas constitution requires voter approval of any tax imposed on the net income of natural persons, including a person’s share of partnership or unincorporated association income; such approval was not obtained for the Texas Margin Tax. The Comptroller has requested that the Attorney General determine whether the direct imposition of the Texas Margin Tax on partnerships without voter approval violates this constitutional requirement. The Attorney General’s decision is not expected until late 2006 or early 2007. If the Texas Margin Tax is ultimately challenged in court, the legislation enacting the Texas Margin Tax gives the Texas Supreme Court jurisdiction over the constitutional challenge and allows the Court to grant injunctive or declaratory relief. The Court would have 120 days from the date the challenge is filed to make a ruling.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
AND RISK FACTORS

     This quarterly report contains various forward-looking statements and information based on our beliefs and those of Enterprise Products GP, our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations (as reflected in such forward-looking statements) are reasonable, neither we nor Enterprise Products GP can give any assurance that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements.

     When considering forward-looking statements, please read Part II, Item 1A, “Risk Factors,” included within this quarterly report on Form 10-Q and Part I, Item 1A, “Risk Factors,” included in our annual report on Form 10-K for 2005.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk.

     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

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

     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.

     The following table shows the effect of hypothetical price movements on the estimated fair value (“FV”) of our interest rate swap portfolio and the related change in fair value of the underlying debt at the dates indicated (dollars in thousands). Income is not affected by changes in the fair value of these swaps; however, these swaps effectively convert the hedged portion of fixed-rate debt to variable-rate debt. As a result, interest expense (and related cash outlays for debt service) will increase or decrease with the change in the periodic “reset” rate associated with the respective swap. Typically, the reset rate is an agreed upon index rate published on the first day of each six-month interest calculation period.

	Resulting	Swap Fair Value at
Scenario	Classification	June 30, 2006			July 20, 2006
FV assuming no change in underlying interest rates	Asset (Liability)	$	(64,869	)	$	(56,350	)
FV assuming 10% increase in underlying interest rates	Asset (Liability)		(98,063	)		(88,615	)
FV assuming 10% decrease in underlying interest rates	Asset (Liability)		(31,676	)		(24,085	)

     The change in fair value of our interest rate swaps since December 31, 2005 is primarily due to an increase in interest rates.

     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

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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. 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.

     We assess the risk of our commodity financial instrument portfolio using a sensitivity analysis model. This analysis measures potential income or loss resulting from changes in fair value of the portfolio, based upon a hypothetical 10% change in the underlying quoted market prices of the commodity financial instruments. The following table shows the effect of such hypothetical price movements on the estimated fair value of our commodity financial instrument portfolio at the dates indicated (dollars in thousands):

	Resulting	Commodity Financial Instrument Portfolio FV
Scenario	Classification	June 30, 2006			July 20, 2006
FV assuming no change in underlying commodity prices	Asset (Liability)	$	(7,785	)	$	(5,791	)
FV assuming 10% increase in underlying commodity prices	Asset (Liability)		(16,536	)		(13,653	)
FV assuming 10% decrease in underlying commodity prices	Asset (Liability)		966			2,072

Effect of financial instruments on accumulated other comprehensive income

     The following table summarizes the effect of our cash flow hedging financial instruments on 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.

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Item 4. Controls and Procedures.

     Our management, with the participation of the chief executive officer (“CEO”) and chief financial officer (“CFO”) of our general partner, has evaluated the effectiveness of our disclosure controls and procedures, including internal controls over financial reporting, as of the end of the period covered by this report. Based on their evaluation, the CEO and CFO of our general partner have concluded that our disclosure controls and procedures are effective to ensure that material information relating to our partnership is made known to management on a timely basis. Our CEO and CFO noted no material weaknesses in the design or operation of our internal controls over financial reporting that are likely to adversely affect our ability to record, process, summarize and report financial information. Also, they detected no fraud involving management or employees who have a significant role in our internal controls over financial reporting.

     There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) that have not been evaluated by management and no other factors that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.

     Collectively, these disclosure controls and procedures are designed to provide us with reasonable assurance that the information required to be disclosed in our periodic reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected.

     The certifications of our general partner’s CEO and CFO required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been included as exhibits to this quarterly report on Form 10-Q.

PART II. OTHER INFORMATION.

Item 1. Legal Proceedings.

     See Part I, Item 1, Financial Statements, Note 15, “Commitments and Contingencies – Litigation,” which is incorporated herein by reference.

Item 1A. Risk Factors.

     Apart from that discussed below, there have been no significant changes in our risk factors since December 31, 2005. For a detailed discussion of our risk factors, please read, Item 1A “Risk Factors,” in our annual report on Form 10-K for 2005.

Tax Risks to Common Unitholders

If we were to become subject to entity level taxation for federal or state tax purposes, then our cash available for distribution to common unitholders would be substantially reduced.

     The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service on this matter.

     If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and we likely would pay state taxes as well. Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses or deductions would flow though to our unitholders. Because a tax would be imposed upon us as a corporation, the cash available for distributions to our common unitholders

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would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.

     Current law may change, causing us to be treated as a corporation for United States federal income tax purposes or otherwise subjecting us to entity level taxation. For example, because of widespread state budget deficits, certain states, including Texas, have taken steps to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. To the extent any state imposes an income tax or other tax upon us as an entity, the cash available for distribution to our common unitholders would be reduced.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

     We did not repurchase any of our common units during the three and six months ended June 30, 2006. As of June 30, 2006, we and our affiliates are authorized to repurchase up to 618,400 common units under the December 1998 common unit repurchase program.

Item 3. Defaults Upon Senior Securities.

     None.

Item 4. Submission of Matters to a Vote of Security Holders.

     None.

Item 5. Other Information.

     None.

Item 6. Exhibits.

Exhibit
Number	Exhibit*
2.1	Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 26, 2000).
2.2	Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 8, 2002.)
2.3	Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 8, 2002).
2.4	Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Form 8-K filed August 12, 2002).
2.5	Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 12, 2002).
2.6	Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.7	Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.8	Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products

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Exhibit
Number	Exhibit*
	Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
2.9	Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to the Form 8-K filed April 21, 2004).
2.10	Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003, (incorporated by reference to Exhibit 2.3 to Form 8-K filed December 15, 2003).
2.11	Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C. adopted by Enterprise Products GTM, LLC as of September 30, 2004 (incorporated by reference to Exhibit 2.11 to Registration Statement on Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
2.12	Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
3.1	Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 10, 2005).
3.2	Third Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of August 29, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 1, 2005).
3.3	Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (restated to include all agreements through December 10, 2003)(incorporated by reference to Exhibit 3.1 to Form 8-K filed July 1, 2005).
3.4	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.5	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
4.1	$2.25 Billion 364-Day Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citicorp North America, Inc. and Lehman Commercial Paper Inc., as Co-Syndication Agents, JPMorgan Chase Bank, UBS Loan Finance LLC and Morgan Stanley Senior Funding, Inc., as Co-Documentation Agents, Wachovia Capital Markets, LLC, Citigroup Global Markets Inc. and Lehman Brothers Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.3 to Form 8-K filed on August 30, 2004).
4.2	Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed on October 6, 2004).
4.3#	Second Amendment dated June 22, 2006, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, CitiBank, N.A. and JPMorgan Chase Bank, as CO-Syndication Agents, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents.
4.4	Eighth Supplemental Indenture dated as of July 18, 2006 to Indenture dated October 4, 2004 among Enterprise Products Operating L.P., as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee. (incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19, 2006).
4.5	Form of Junior Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed July 19, 2005).

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Exhibit
Number	Exhibit*
4.6#	Purchase Agreement, dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P., as Guarantor, and Enterprise Products Partners L.P., as Buyer.
18.1	Letter regarding Change in Accounting Principles dated May 4, 2004 (incorporated by reference to Exhibit 18.1 to Form 10-Q filed May 10, 2004).
31.1#	Sarbanes-Oxley Section 302 certification of Robert G. Phillips for Enterprise Products Partners L.P. for the June 30, 2006 quarterly report on Form 10-Q.
31.2#	Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the June 30, 2006 quarterly report on Form 10-Q.
32.1#	Section 1350 certification of Robert G. Phillips for the June 30, 2006 quarterly report on Form 10-Q.
32.2#	Section 1350 certification of Michael A. Creel for the June 30, 2006 quarterly report on Form 10-Q.

*	With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323.
#	Filed with this report.

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SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this quarterly report on Form 10-Q to be signed on its behalf by the undersigned thereunto duly authorized, in the City of Houston, State of Texas on August 8, 2006.

ENTERPRISE PRODUCTS PARTNERS L.P.
(A Delaware Limited Partnership)
By:	Enterprise Products GP, LLC,
	as General Partner
By:	/s/ Michael J. Knesek
Name:	Michael J. Knesek
Title:	Senior Vice President, Controller and Principal Accounting Officer of the General Partner

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INDEX TO EXHIBITS

Exhibit
Number	Exhibit*
2.1	Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Form 8-K filed September 26, 2000).
2.2	Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 8, 2002.)
2.3	Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Form 8-K filed February 8, 2002).
2.4	Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Form 8-K filed August 12, 2002).
2.5	Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Form 8-K filed August 12, 2002).
2.6	Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
2.7	Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
2.8	Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products

Exhibit
Number	Exhibit*
	Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
2.9	Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to the Form 8-K filed April 21, 2004).
2.10	Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003, (incorporated by reference to Exhibit 2.3 to Form 8-K filed December 15, 2003).
2.11	Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C. adopted by Enterprise Products GTM, LLC as of September 30, 2004 (incorporated by reference to Exhibit 2.11 to Registration Statement on Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
2.12	Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
3.1	Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 10, 2005).
3.2	Third Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of August 29, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed September 1, 2005).
3.3	Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (restated to include all agreements through December 10, 2003)(incorporated by reference to Exhibit 3.1 to Form 8-K filed July 1, 2005).
3.4	Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
3.5	Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
4.1	$2.25 Billion 364-Day Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, Citicorp North America, Inc. and Lehman Commercial Paper Inc., as Co-Syndication Agents, JPMorgan Chase Bank, UBS Loan Finance LLC and Morgan Stanley Senior Funding, Inc., as Co-Documentation Agents, Wachovia Capital Markets, LLC, Citigroup Global Markets Inc. and Lehman Brothers Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.3 to Form 8-K filed on August 30, 2004).
4.2	Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed on October 6, 2004).
4.3#	Second Amendment dated June 22, 2006, to Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, CitiBank, N.A. and JPMorgan Chase Bank, as CO-Syndication Agents, and Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents.
4.4	Eighth Supplemental Indenture dated as of July 18, 2006 to Indenture dated October 4, 2004 among Enterprise Products Operating L.P., as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee. (incorporated by reference to Exhibit 4.2 to Form 8-K filed July 19, 2006).
4.5	Form of Junior Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K filed July 19, 2005).

Exhibit
Number	Exhibit*
4.6#	Purchase Agreement, dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P., as Guarantor, and Enterprise Products Partners L.P., as Buyer.
18.1	Letter regarding Change in Accounting Principles dated May 4, 2004 (incorporated by reference to Exhibit 18.1 to Form 10-Q filed May 10, 2004).
31.1#	Sarbanes-Oxley Section 302 certification of Robert G. Phillips for Enterprise Products Partners L.P. for the June 30, 2006 quarterly report on Form 10-Q.
31.2#	Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the June 30, 2006 quarterly report on Form 10-Q.
32.1#	Section 1350 certification of Robert G. Phillips for the June 30, 2006 quarterly report on Form 10-Q.
32.2#	Section 1350 certification of Michael A. Creel for the June 30, 2006 quarterly report on Form 10-Q.

*	With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323.
#	Filed with this report.

EX-4.3

EXHIBIT 4.3

SECOND AMENDMENT TO
MULTI-YEAR REVOLVING CREDIT AGREEMENT

     THIS SECOND AMENDMENT TO MULTI-YEAR REVOLVING CREDIT AGREEMENT (this “Second Amendment”) is made and entered into as of the 22^nd day of June, 2006 (the “Second Amendment Effective Date”), among ENTERPRISE PRODUCTS OPERATING L.P., a Delaware limited partnership (“Borrower”); WACHOVIA BANK, NATIONAL ASSOCIATION, as administrative agent (in such capacity, the “Administrative Agent”) for each of the lenders (the “Lenders”) that is a signatory or which becomes a signatory to the hereinafter defined Credit Agreement; and the Lenders party hereto.

R E C I T A L S:

     A. On August 25, 2004, the Borrower, the Lenders and the Administrative Agent entered into a certain Multi-Year Revolving Credit Agreement, amended by that certain First Amendment to Multi-Year Revolving Credit Agreement dated October 5, 2005 (the “Credit Agreement”) whereby, upon the terms and conditions therein stated, the Lenders agreed to make certain Loans (as defined in the Credit Agreement) and extend certain credit to the Borrower.

     B. The parties hereto mutually desire to amend the Credit Agreement as hereinafter set forth.

     NOW, THEREFORE, in consideration of the mutual covenants and agreements herein contained, the Borrower, the Lenders party hereto and the Administrative Agent hereby agree as follows:

     1. Certain Definitions.

     1.1 Terms Defined Above. As used in this Second Amendment, the terms “Administrative Agent”, “Borrower”, “Credit Agreement”, “Second Amendment” and “Second Amendment Effective Date”, shall have the meanings indicated above.

     1.2 Terms Defined in Agreement. Unless otherwise defined herein, all terms beginning with a capital letter which are defined in the Credit Agreement shall have the same meanings herein as therein unless the context hereof otherwise requires.

     2. Amendments to Credit Agreement.

     2.1 Defined Terms.

     (a) The term “Agreement,” as defined in Section 1.01 of the Credit Agreement, is hereby amended to mean the Credit Agreement, as amended and supplemented by this Second Amendment and as the same may from time to time be further amended or supplemented.

     (b) The definition of “Consolidated Net Worth” as defined in Section 1.01 of the Credit Agreement is hereby amended in its entirety to read as follows:

     “Consolidated Net Worth” means as to any Person, at any date of determination, the sum of (i) preferred stock (if any), (ii) an amount equal to (a) the face amount of outstanding Hybrid Securities not in excess of 15% of Consolidated Total Capitalization times (b) sixty-two and one-half percent (62.5%), (iii) par value of common stock, (iv)

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capital in excess of par value of common stock, (v) partners’ capital or equity, and (vi) retained earnings, less treasury stock (if any), of such Person, all as determined on a consolidated basis.

     2.2 Additional Defined Terms. Section 1.01 of the Credit Agreement is hereby further amended and supplemented by adding the following new definitions, which read in their entirety as follows:

     “Commercial Operation Date” means the date on which a Material Project is substantially complete and commercially operable.

     “Consolidated Total Capitalization” means the sum of (i) Consolidated Indebtedness and (ii) Borrower’s Consolidated Net Worth.

     “Hybrid Securities” means any trust preferred securities, or deferrable interest subordinated debt with a maturity of at least 20 years, which provides for the optional or mandatory deferral of interest or distributions, issued by the Borrower, or any business trusts, limited liability companies, limited partnerships or similar entities (i) substantially all of the common equity, general partner or similar interests of which are owned (either directly or indirectly through one or more wholly owned Subsidiaries) at all times by the Borrower or any of its Subsidiaries, (ii) that have been formed for the purpose of issuing hybrid securities or deferrable interest subordinated debt, and (iii) substantially all the assets of which consist of (A) subordinated debt of the Borrower or a Subsidiary of the Borrower, and (B) payments made from time to time on the subordinated debt.

     “LIBOR Market Index Rate” means, for any day, with respect to any LMIR Borrowing or LMIR Loan (a) the rate per annum appearing on Page 3750 of the Bridge Telerate Service (formerly Dow Jones Market Service) (or on any successor or substitute page of such Service, or any successor to or substitute for such Service, providing rate quotations comparable to those currently provided on such page of such Service, as determined by the Swingline Lender from time to time for purposes of providing quotations of interest rates applicable to dollar deposits in the London interbank market) at approximately 11:00 a.m., London time for such day, provided, if such day is not a Business Day, the immediately preceding Business Day, as the rate for dollar deposits with a one-month maturity; (b) if for any reason the rate specified in clause (a) of this definition does not so appear on Page 3750 of the Bridge Telerate Service (or any successor or substitute page or any such successor to or substitute for such Service), the rate per annum appearing on Reuters Screen LIBO page (or any successor or substitute page) as the London interbank offered rate for deposits in dollars at approximately 11:00 a.m., London time, for such day, provided, if such day is not a Business Day, the immediately preceding Business Day, for a one-month maturity; and (c) if the rate specified in clause (a) of this definition does not so appear on Page 3750 of the Bridge Telerate Service (or any successor or substitute page or any such successor to or substitute for such Service) and if no rate specified in clause (b) of this definition so appears on Reuters Screen LIBO page (or any successor or substitute page), the average of the interest rates per annum at which dollar deposits of $5,000,000 and for a one-month maturity are offered by the respective principal London offices of the Reference Banks in immediately available funds in the London interbank market at approximately 11:00 a.m., London time, for such day.

2

     “LMIR”, when used in reference to any Loan or Borrowing, refers to a Loan, or Loans, in the case of a Borrowing, which bear interest at a rate determined by reference to the LIBOR Market Index Rate.

     “Material Project” means the construction or expansion of any capital project of the Borrower or any of its Subsidiaries, the aggregate capital cost of which exceeds $50,000,000.

     “Material Project EBITDA Adjustments” shall mean, with respect to each Material Project:

     (A) prior to the Commercial Operation Date of a Material Project (but including the fiscal quarter in which such Commercial Operation Date occurs), a percentage (based on the then-current completion percentage of such Material Project) of an amount to be approved by the Administrative Agent as the projected Consolidated EBITDA of Borrower and its Subsidiaries attributable to such Material Project for the first 12-month period following the scheduled Commercial Operation Date of such Material Project (such amount to be determined based on customer contracts or tariff-based customers relating to such Material Project, the creditworthiness of the other parties to such contracts or such tariff-based customers, and projected revenues from such contracts, tariffs, capital costs and expenses, scheduled Commercial Operation Date, oil and gas reserve and production estimates, commodity price assumptions and other factors deemed appropriate by Administrative Agent), which may, at the Borrower’s option, be added to actual Consolidated EBITDA for the Borrower and its Subsidiaries for the fiscal quarter in which construction of such Material Project commences and for each fiscal quarter thereafter until the Commercial Operation Date of such Material Project (including the fiscal quarter in which such Commercial Operation Date occurs, but net of any actual Consolidated EBITDA of the Borrower and its Subsidiaries attributable to such Material Project following such Commercial Operation Date); provided that if the actual Commercial Operation Date does not occur by the scheduled Commercial Operation Date, then the foregoing amount shall be reduced, for quarters ending after the scheduled Commercial Operation Date to (but excluding) the first full quarter after its Commercial Operation Date, by the following percentage amounts depending on the period of delay (based on the period of actual delay or then-estimated delay, whichever is longer): (i) 90 days or less, 0%, (ii) longer than 90 days, but not more than 180 days, 25%, (iii) longer than 180 days but not more than 270 days, 50%, and (iv) longer than 270 days, 100%; and

     (B) beginning with the first full fiscal quarter following the Commercial Operation Date of a Material Project and for the two immediately succeeding fiscal quarters, an amount to be approved by the Administrative Agent as the projected Consolidated EBITDA of Borrower and its Subsidiaries attributable to such Material Project (determined in the same manner as set forth in clause (A) above) for the balance of the four full fiscal quarter period following such Commercial Operation Date, which may, at the Borrower’s option, be added to actual Consolidated EBITDA for the Borrower and its Subsidiaries for such fiscal quarters.

     Notwithstanding the foregoing:

     (i) no such additions shall be allowed with respect to any Material Project unless:

3

     (a) not later than 30 days prior to the delivery of any certificate required by the terms and provisions of Section 5.01(e) to the extent Material Project EBITDA Adjustments will be made to Consolidated EBITDA in determining compliance with Section 6.07(b), the Borrower shall have delivered to the Administrative Agent written pro forma projections of Consolidated EBITDA of the Borrower and its Subsidiaries attributable to such Material Project and

     (b) prior to the date such certificate is required to be delivered, the Administrative Agent shall have approved (such approval not to be unreasonably withheld) such projections and shall have received such other information and documentation as the Administrative Agent may reasonably request, all in form and substance satisfactory to the Administrative Agent, and

     (ii) the aggregate amount of all Material Project EBITDA Adjustments during any period shall be limited to 15% of the total actual Consolidated EBITDA of the Borrower and its Subsidiaries for such period (which total actual Consolidated EBITDA shall be determined without including any Material Project EBITDA Adjustments).

     “Second Amendment” means that certain Second Amendment to Multi-Year Revolving Credit Agreement dated as of June 22, 2006, among the Borrower, the Lenders party thereto and the Administrative Agent.

     “Second Amendment Effective Date” means June 22, 2006.

     2.3 Eurodollar Revolving Borrowings. The reference to “six Eurodollar Revolving Borrowings” set forth in the proviso at the end of the last sentence of Section 2.02(c) of the Credit Agreement is hereby amended in its entirety to refer instead to “twelve Eurodollar Revolving Borrowings”.

     2.4 Swingline Loans.

     (a) The reference to “outstanding Swingline Loans exceeding $20,000,000” set forth in subclause (i) of the first sentence of Section 2.05(a) of the Credit Agreement is hereby amended in its entirety to refer instead to “outstanding Swingline Loans exceeding $75,000,000”.

     (b) The second sentence of Section 2.02(b) of the Credit Agreement is hereby amended in its entirety to read as follows:

Each Swingline Loan shall (i) prior to the acquisition by any Lender of a participation therein pursuant to Section 2.05(c), be an LMIR Loan, and (ii) upon and following the acquisition by any Lender of a participation therein, be an ABR Loan.

     (c) Section 2.13(a) of the Credit Agreement is hereby amended in its entirety to read as follows:

     (a) The Loans comprising each ABR Borrowing shall bear interest on each day at the Alternate Base Rate for such day. The Loans comprising each Swingline Loan shall (i) prior the acquisition by any Lender of a participation therein pursuant to Section 2.05(c), bear interest on each day at the LIBOR Market Index Rate for such day plus an amount equal to the “Eurodollar Spread” set forth in the pricing grid set forth in the

4

defined term “Applicable Rate” that would be applicable to Eurodollar Revolving Loans on such day, and (ii) upon and following the acquisition by any Lender of a participation therein, bear interest on each day at the Alternate Base Rate for such day.

     2.5 Restrictive Agreements. Section 6.06 of the Credit Agreement is hereby amended and supplemented by adding a new clause (xiii) at the end thereof, to read as follows:

or (xiii) that is a Hybrid Security or an indenture, document, agreement or security entered into or issued in connection with a Hybrid Security or otherwise constituting a restriction or condition on the payment of dividends or distributions by an issuer of a Hybrid Security.

     2.6 Financial Covenants. Section 6.07(b) of the Credit Agreement is hereby amended and supplemented by adding a new paragraph at the end thereof, to read as follows:

In addition, for purposes of this Section 6.07(b), Hybrid Securities up to an aggregate amount of 15% of Consolidated Total Capitalization shall be excluded from Consolidated Indebtedness and Consolidated EBITDA may include, at Borrower’s option, any Material Project EBITDA Adjustments as provided in the definition thereof.

     2.7 Swingline Loan Note. Exhibit I to the Credit Agreement is hereby amended in its entirety to read as set forth on Exhibit I attached hereto.

     2.8 Extension of Maturity Date. Borrower has, pursuant to Section 2.01(c) of the Credit Agreement requested a one-year extension of the Maturity Date and that the notice requirement with respect thereto be waived. Each Lender a party hereto hereby consents to a one-year extension of the Maturity Date to October 5, 2011 and waives the notice requirement set forth in such Section 2.01(c) with respect thereto. Furthermore, each Lender a party hereto hereby agrees that following the effectiveness hereof, Borrower shall continue to have the right to make up to two (2) additional requests for one-year extensions of the Maturity Date under Section 2.01(c).

     2.9 Conditions Precedent. The obligation of the Lenders party hereto and the Administrative Agent to enter into this Second Amendment shall be conditioned upon the following conditions precedent:

     (a) The Administrative Agent shall have received a copy of this Second Amendment, duly completed and executed by the Borrower and Required Lenders; and acknowledged and ratified by the Limited Partner pursuant to a duly executed Acknowledgement and Ratification in the form of Exhibit A attached hereto;

     (b) The Administrative Agent shall have received favorable written opinions (addressed to the Administrative Agent and the Lenders and dated the Second Amendment Effective Date) of Richard Bachmann, in-house counsel for Borrower and the Limited Partner, and Bracewell & Giuliani LLP, counsel for Borrower and the Limited Partner, substantially in the forms delivered in connection with the First Amendment and reasonably satisfactory to the Administrative Agent and its counsel.

     (c) The Administrative Agent shall have received such documents and certificates as the Administrative Agent or its counsel may reasonably request relating to (1) the organization

5

and existence of the Borrower and the Limited Partner, (2) the authorization of this Second Amendment and any other legal matters relating to the Borrower, this Second Amendment or the Credit Agreement, all in form and substance reasonably satisfactory to the Administrative Agent and its counsel, and (3) with respect to the Limited Partner, the authorization of the Ratification and Acknowledgement of Limited Partner attached hereto, and any other legal matters relating to the Limited Partner.

     (d) The Swingline Lender shall have received a swingline loan note, duly completed and executed by the Borrower.

     (e) The Administrative Agent shall have received a certificate, dated the Second Amendment Effective Date and signed by the President, an Executive Vice President or a Financial Officer of the Borrower, confirming compliance with the conditions set forth in paragraphs (a) and (b) of Section 4.02 of the Credit Agreement, as amended hereby, and Section 2.9(g) hereof.

     (f) The Administrative Agent shall have received all fees and other amounts due and payable on or prior to the Second Amendment Effective Date, including, to the extent invoiced five (5) Business Days prior to closing, reimbursement or payment of all out-of-pocket expenses required to be reimbursed or paid by the Borrower hereunder.

     (g) As of the Second Amendment Effective Date, no Material Adverse Change exists.

     (h) The Administrative Agent shall have received such other information, documents or instruments as it or its counsel may reasonably request.

     3. Representations and Warranties. The Borrower represents and warrants that:

     (a) there exists no Default or Event of Default, or any condition or act which constitutes, or with notice or lapse of time or both would constitute, an Event of Default under the Credit Agreement, as hereby amended and supplemented;

     (b) the Borrower has performed and complied with all covenants, agreements and conditions contained in the Credit Agreement, as hereby amended and supplemented, required to be performed or complied with by it; and

     (c) the representations and warranties of the Borrower contained in the Credit Agreement, as hereby amended and supplemented, were true and correct in all material respects when made, and are true and correct in all material respects at and as of the time of delivery of this Second Amendment, except to the extent such representations and warranties relate to an earlier date, in which case such representations and warranties were true and correct in all material respects as of such earlier date.

     4. Extent of Amendments. Except as expressly herein set forth, all of the terms, conditions, defined terms, covenants, representations, warranties and all other provisions of the Credit Agreement are herein ratified and confirmed and shall remain in full force and effect.

     5. Counterparts. This Second Amendment may be executed in two or more counterparts, and it shall not be necessary that the signatures of all parties hereto be contained on any one counterpart hereof; each counterpart shall be deemed an original, but all of which together shall constitute one and the same instrument.

6

     6. References. On and after the Second Amendment Effective Date, the terms “Agreement”, “hereof”, “herein”, “hereunder”, and terms of like import when used in the Credit Agreement shall, except where the context otherwise requires, refer to the Credit Agreement, as amended and supplemented by this Second Amendment.

     7. Governing Law. This Second Amendment shall be governed by and construed in accordance with the laws of the State of New York and applicable federal law.

     THIS SECOND AMENDMENT, THE CREDIT AGREEMENT, AS AMENDED HEREBY, THE NOTES AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.

     THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

     This Second Amendment shall benefit and bind the parties hereto, as well as their respective assigns, successors, heirs and legal representatives.

[Signatures Begin on Next Page]

7

     EXECUTED as of the Second Amendment Effective Date.

BORROWER:
ENTERPRISE PRODUCTS OPERATING L.P.
By:	Enterprise Products OLPGP, Inc.,
	General Partner
By:	/s/ W. Randall Fowler
Name:	W. Randall Fowler
Title:	Senior Vice President and Treasurer

WACHOVIA BANK,
NATIONAL ASSOCIATION,
Individually, as Administrative Agent, as Issuing Bank and as Swingline Lender
By:	/s/ Shannan Townsend
Name:	Shannan Townsend
Title:	Director

CITIBANK, N.A.
Individually and as Co-Syndication Agent
By:	/s/ Todd J. Mogil
Name:	Todd J. Mogil
Title:	Attorney-in-Fact

JPMORGAN CHASE BANK,
Individually and as Co-Syndication Agent
By:	/s/ Dianne L. Russell
Name:	Dianne L. Russell
Title:	Vice President

MIZUHO CORPORATE BANK, LTD.,
Individually and as Co-Documentation Agent
By:	/s/ Raymond Ventura
Name:	Raymond Ventura
Title:	Deputy General Manager

SUNTRUST BANK,
Individually and as Co-Documentation Agent
By:	/s/ Peter Panos
Name:	Peter Panos
Title:	Vice President

THE BANK OF NOVA SCOTIA,
Individually and as Co-Documentation Agent
By:	/s/ V. H. Gibson
Name:	V. H. Gibson
Title:	Assistant Agent

BARCLAYS BANK PLC,
Individually and as a Senior Managing Agent
By:	/s/ Nicholas Bell
Name:	Nicholas Bell
Title:	Director

BAYERISCHE HYPO-UND VEREINSBANK
AG, NEW YORK BRANCH, Individually and as
a Senior Managing Agent
By:	/s/ Yoram Dankner
Name:	Yoram Dankner
Title:	Managing Director
By:	/s/ Shannon Batchman
Name:	Shannon Batchman
Title:	Director

BMO CAPITAL MARKETS FINANCING, INC.,
Individually and as a Senior Managing Agent
By:	/s/ Cahal Carmody
Name:	Cahal Carmody
Title:	Vice President

THE ROYAL BANK OF SCOTLAND plc,
Individually and as a Senior Managing Agent
By:	/s/ Matthew Main
Name:	Matthew Main
Title:	Managing Director

BANK OF AMERICA, N.A.,
Individually and as a Managing Agent
By:	/s/ Zewditu Menelik
Name:	Zewditu Menelik
Title:	Vice President

THE BANK OF TOKYO-MITSUBISHI UFJ,
LTD., HOUSTON AGENCY,
Individually and as a Managing Agent
By:	/s/ Kelton Glasscock
Name:	Kelton Glasscock
Title:	Vice President & Manager

BNP PARIBAS,
Individually and as a Managing Agent
By:	/s/ J. Onischuk
Name:	J. Onischuk
Title:	Director
By:	/s/ Greg Smothers
Name:	Greg Smothers
Title:	Vice President

LEHMAN COMMERCIAL PAPER INC.,
Individually and as a Managing Agent
By:	/s/ Janine M. Shugan
Name:	Janine M. Shugan
Title:	Authorized Signatory

MORGAN STANLEY BANK,
Individually and as a Managing Agent
By:	/s/ Daniel Twenge
Name:	Daniel Twenge
Title:	Vice President

UBS LOAN FINANCE LLC,
Individually and as a Managing Agent
By:	/s/ Richard L. Tavrow
Name:	Richard L. Tavrow
Title:	Director
By:	/s/ Irja R. Otsa
Name:	Irja R. Otsa
Title:	Associate Director

SOCIETE GENERALE,
Individually and as Co-Agent
By:	/s/ Stephen W. Warfel
Name:	Stephen W. Warfel
Title:	Director

GOLDMAN SACHS CREDIT PARTNERS L.P.,
a Lender
By:	/s/ Pedro Ramirez
Name:	Pedro Ramirez
Title:	Authorized Signatory

ING CAPITAL LLC, a Lender
By:	/s/ Richard Ennis
Name:	Richard Ennis
Title:	Managing Director

SUMITOMO MITSUI BANKING
CORPORATION, a Lender
By:	/s/ William M. Ginn
Name:	William M. Ginn
Title:	General Manager

BAYERISCHE LANDESBANK,
NEW YORK BRANCH,
Individually and as Co-Agent
By:	/s/ Stephen Christenson
Name:	Stephen Christenson
Title:	First Vice President
By:	/s/ Norman McClave
Name:	Norman McClave
Title:	First Vice President

DNB NOR BANK ASA,
Individually and as Co-Agent
By:	/s/ Philip F. Kurpiewski
Name:	Philip F. Kurpiewski
Title:	Senior Vice President
By:	/s/ Giacomo Landi
Name:	Giacomo Landi
Title:	First Vice President

ROYAL BANK OF CANADA,
Individually and as Co-Agent
By:	/s/ David McCluskey
Name:	David McCluskey
Title:	Authorized Signatory

MERRILL LYNCH BANK USA, a Lender
By:	/s/ Louis Alder
Name:	Louis Alder
Title:	Director

WELLS FARGO BANK,
NATIONAL ASSOCIATION, a Lender
By:	/s/ Jo Ann Vasquez
Name:	Jo Ann Vasquez
Title:	Vice President

CAPITAL ONE, N.A., a Lender
By:	/s/ Nancy G. Morages
Name:	Nancy G. Morages
Title:	Senior Vice President

EXHIBIT A

ACKNOWLEDGMENT AND RATIFICATION OF GUARANTOR

     The undersigned (“Guarantor”) hereby expressly (i) acknowledges the terms of the foregoing Second Amendment to Multi-Year Revolving Credit Agreement; (ii) ratifies and affirms its obligations under its Guaranty Agreement dated as of August 25, 2004, in favor of the Administrative Agent; (iii) acknowledges, renews and extends its continued liability under said Guaranty Agreement and Guarantor hereby agrees that its Guaranty Agreement remains in full force and effect; and (iv) guarantees to the Administrative Agent the prompt payment when due of all amounts owing or to be owing by it under its Guaranty Agreement pursuant to the terms and conditions thereof, as modified hereby.

     The foregoing acknowledgment and ratification of the undersigned Guarantor shall be evidenced by signing the space provided below, to be effective as of the Second Amendment Effective Date.

ENTERPRISE PRODUCTS PARTNERS L.P.,
a Delaware limited partnership
By:	Enterprise Products GP, LLC,
	General Partner
By:	/s/ W. Randall Fowler
	W. Randall Fowler
	Senior Vice President and Treasurer

EXHIBIT I

FORM OF
SWINGLINE LOAN NOTE
(Multi-Year Credit Facility)

$75,000,000.00 June 22, 2006

     ENTERPRISE PRODUCTS OPERATING L.P., a Delaware limited partnership (the “Borrower”), for value received, promises and agrees to pay to WACHOVIA BANK, NATIONAL ASSOCIATION, as Swingline Lender under the Credit Agreement, as hereafter defined (the “Swingline Lender”), or order, at the payment office of WACHOVIA BANK, NATIONAL ASSOCIATION, as Administrative Agent, at 301 South College Street, Charlotte, North Carolina 28288-0608, the principal sum of SEVENTY-FIVE MILLION AND NO/100 DOLLARS ($75,000,000.00), or such lesser amount as shall equal the aggregate unpaid principal amount of the Swingline Loans owed to the Swingline Lender under the Credit Agreement, in lawful money of the United States of America and in immediately available funds, on the dates and in the principal amounts provided in the Credit Agreement, and to pay interest on the unpaid principal amount as provided in the Credit Agreement for such Swingline Loans, at such office, in like money and funds, for the period commencing on the date of each such Swingline Loan until such Swingline Loan shall be paid in full, at the rates per annum and on the dates provided in the Credit Agreement.

     This note evidences the Swingline Loans owed to the Swingline Lender under that certain Multi-Year Revolving Credit Agreement dated as of August 25, 2004, by and among the Borrower, Wachovia Bank, National Association, individually, as Administrative Agent, Issuing Bank and Swingline Lender, Citibank, N.A. and JPMorgan Chase Bank, individually and as Co-Syndication Agents, Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, individually and as Co-Documentation Agents, and the other financial institutions parties thereto (such Credit Agreement, together with all amendments or supplements thereto, being the “Credit Agreement”), and shall be governed by the Credit Agreement. Capitalized terms used in this note and not defined in this note, but which are defined in the Credit Agreement, have the respective meanings herein as are assigned to them in the Credit Agreement.

     The Swingline Lender is hereby authorized by the Borrower to endorse on Schedule A (or a continuation thereof) attached to this note, the amount and date of each payment or prepayment of principal of each such Swingline Loan received by the Swingline Lender, provided that any failure by the Swingline Lender to make any such endorsement shall not affect the obligations of the Borrower under the Credit Agreement or under this note in respect of such Swingline Loans.

     This note may be held by the Swingline Lender for the account of its applicable lending office and, except as otherwise provided in the Credit Agreement, may be transferred from one lending office of the Swingline Lender to another lending office of the Swingline Lender from time to time as the Swingline Lender may determine.

     Except only for any notices which are specifically required by the Credit Agreement, the Borrower and any and all co-makers, endorsers, guarantors and sureties severally waive

notice (including but not limited to notice of intent to accelerate and notice of acceleration, notice of protest and notice of dishonor), demand, presentment for payment, protest, diligence in collecting and the filing of suit for the purpose of fixing liability, and consent that the time of payment hereof may be extended and re-extended from time to time without notice to any of them. Each such person agrees that its liability on or with respect to this note shall not be affected by any release of or change in any guaranty or security at any time existing or by any failure to perfect or maintain perfection of any lien against or security interest in any such security or the partial or complete unenforceability of any guaranty or other surety obligation, in each case in whole or in part, with or without notice and before or after maturity.

     The Credit Agreement provides for the acceleration of the maturity of this note upon the occurrence of certain events and for prepayment of Swingline Loans upon the terms and conditions specified therein. Reference is made to the Credit Agreement for all other pertinent purposes.

     This note is issued pursuant to and is entitled to the benefits of the Credit Agreement.

     It is hereby understood and agreed that Enterprise Products OLPGP, Inc., the general partner of the Borrower, shall have no personal liability, as general partner or otherwise, for the payment of any amount owing or to be owing hereunder.

     This note shall be construed in accordance with and be governed by the law of the State of New York and the United States of America from time to time in effect.

ENTERPRISE PRODUCTS OPERATING L.P.
By:	Enterprise Products OLPGP, Inc.,
	General Partner
By:
	Name:
	Title:

SCHEDULE A

TO
SWINGLINE LOAN NOTE

This note evidences the Swingline Loans owed to the Swingline Lender under the Credit Agreement, in the principal amount set forth below, subject to the payments of principal set forth below:

SCHEDULE
OF
SWINGLINE LOANS AND PAYMENTS OF PRINCIPAL AND INTEREST

	Principal	Amount of		Balance
	Amount of	Principal		of	Notation
	Swingline	Paid or	Interest	Swingline	Made
Date	Loan	Prepaid	Paid	Loans	by

EX-4.6

EXHIBIT 4.6

PURCHASE AGREEMENT

between

CERRITO GATHERING COMPANY, LTD.

CERRITO GAS MARKETING, LTD.

ENCINAL GATHERING, LTD.

as Sellers

LEWIS ENERGY GROUP, L.P.

as Guarantor

and

ENTERPRISE PRODUCTS PARTNERS L.P.

as Buyer

July 12, 2006

Table of Contents

			Page
§1.	Definitions			1
§2.	Purchase and Sale of Assets			15
	(a)	Assets		15
	(b)	Excluded Assets		17
	(c)	Liabilities		17
	(d)	Estimated Purchase Price		18
	(e)	Preliminary Settlement Statement		18
	(f)	Post-Closing Adjustment Procedure		18
	(g)	Final Purchase Price Allocation		19
	(h)	Sellers’ Liability for Taxes		19
	(i)	Prorations		19
	(j)	Closing		19
	(k)	Closing Obligations		20
	(l)	Material Consents		23
§3.	Representations and Warranties of Buyer			24
	(a)	Organization		24
	(b)	Authorization of Transaction		24
	(c)	Non-contravention		25
	(d)	Brokers’ Fees		25
	(e)	Available Funds and Enterprise Units		25
	(f)	Qualified for Gathering System Permits		25
	(g)	Independent Investigation		25
§4.	Representations and Warranties of Sellers			26
	(a)	Organization, Qualification, and Power		26
	(b)	Authorization of Transaction		26
	(c)	Non-contravention		26
	(d)	Brokers’ Fees		26
	(e)	Assets		27
	(f)	Subsequent Events		27
	(g)	Legal Compliance		28
	(h)	Real Property		28
	(i)	Material GS Contracts		29
	(j)	Litigation		30
	(k)	Labor and Employment		30
	(l)	Gathering System Permits		30
	(m)	Environmental Matters		31
	(n)	Insurance		32
	(o)	Governmental Regulation		32
	(p)	Disclosure and Due Diligence		32
	(q)	Taxes		32
	(r)	No Other Agreements to Sell Assets		33
	(s)	Disclaimer of Other Representations and Warranties		33

-i-

			Page
	(t)	Sellers’ Private Placement Representations		35
	(u)	Relationships with Related Persons		35
	(v)	Conveyance Documents		35
	(w)	No Undisclosed Material Liabilities		36
	(x)	Other Information		36
	(y)	Indebtedness		36
§5.	Labor and Employment; Employee Benefits			36
	(a)	Affected Employees		36
	(b)	Employment of Affected Employees by Buyer		36
	(c)	Salaries and Benefits		37
	(d)	Sellers’ Group Health Plans		38
	(e)	Sellers’ Retirement and Savings Plans		39
	(f)	General Employee Provisions		39
§6.	Post-Closing Covenants			40
	(a)	General		40
	(b)	Payment of Obligations Under Lehman Agreement		40
	(c)	Preferential Right to Purchase		40
	(d)	Transition Services		40
	(e)	Post-Closing Settlement of Income and Expenses Received or Paid		41
	(f)	Shelf Registration Rights		41
	(g)	Lock-up of Enterprise Units		45
	(h)	Financial Information		45
	(i)	Customer and Other Business Relationships		46
	(j)	Certain Actions by Sellers		46
	(k)	VOC Site Assessment		46
	(l)	Transfer of Interim Excluded Assets		46
	(m)	Radio Tower and Shared Data Agreement		47
	(n)	Joint Use of Easements and Surface Sites		47
	(o)	Joint Venture Agreement		47
§7.	Remedies for Breaches of This Agreement			47
	(a)	Indemnification Provisions for Buyer’s Benefit		47
	(b)	Indemnification Provisions for Sellers’ Benefit		47
	(c)	Liabilities Non-Recourse to Buyer’s General Partner		48
	(d)	Claims Period		48
	(e)	Buyer Basket; Indemnification		48
	(f)	Determination of Adverse Consequences		49
	(g)	Exclusive Remedy		49
	(h)	Investigations		49
	(i)	Limitation on Damages		49
§8.	Miscellaneous			49
	(a)	No Third-Person Beneficiaries		49
	(b)	Disclosure Schedule		50
	(c)	Entire Agreement		50
	(d)	Succession and Assignment		50
	(e)	Counterparts		50

-ii-

		Page
(f)	Headings		50
(g)	Notices		50
(h)	Governing Law		52
(i)	Arbitration		52
(j)	Amendments and Waivers		52
(k)	Seller Representative		52
(l)	Severability		53
(m)	Expenses		53
(n)	Construction		53
(o)	Incorporation of Exhibits and Schedules		53
(p)	Bold and/or Capitalized Letters		54
(q)	1031 Treatment		54

-iii-

Exhibits and Disclosure Schedule

Exhibits

Exhibit A	Form of Deep Rich Gathering Agreement
Exhibit B	Form of Deep Rich Processing Agreement
Exhibit C	Form of Enterprise Texas Pipeline PSA/Lease Termination Letter
Exhibit D	Form of Lean Gas Gathering Agreement
Exhibit E	Form of LPP Zero Rate Gathering Service Agreement
Exhibit F	Form of Mexico Gathering Agreement
Exhibit G	Form of Mexico Processing Agreement
Exhibit H	Form of Non-Circumvention Agreement
Exhibit I	Form of Parent Guaranty
Exhibit J	Form of Shallow Rich Gathering Agreement
Exhibit K	Form of Shallow Rich Processing Agreement
Exhibit L	Form of Bill of Sale
Exhibit M	Form of Special Warranty Deed
Exhibit N	Form of Gathering Lines Assignment
Exhibit O	Form of Canales 12” Gathering Lines Assignment
Exhibit P	Form of Gathering System Permits Assignment
Exhibit Q	Form of Gathering System Contracts Assignment
Exhibit R	Form of Easements Assignment

Disclosure Schedule

§1(a)	Facilities Holding Condensate Inventory
§1(b)	Indebtedness
§1(c)	Interim Excluded Assets
§1(d)	Knowledge of Buyer
§1(e)	Knowledge of Each Seller
§1(f)	Material Consents
§2(a)(i)	Plant Facilities
§2(a)(ii)	Gathering System Contracts
§2(a)(iii)	Gathering System Permits
§2(a)(iv)	Personal Property
§2(a)(v)	Gathering Lines
§2(a)(vi)	Equipment
§2(a)(x)	Owned Real Property
§2(a)(xi)	Easements
§2(b)(vi)	Excluded Assets
§2(d)	Estimated Purchase Price Allocation Between Cash and Enterprise Units
§2(e)	Preliminary Settlement Statement
§4(c)	Governmental Authority
§4(e)(i)	Asset Title Exceptions
§4(e)(ii)	Assignable Assets Subject to Consent
§4(f)	Subsequent Events

-iv-

§4(f)(viii)	Terminated Principal Customers or Suppliers
§4(g)	Legal Compliance
§4(h)	Owned Real Property
§4(h)(i)	Title to Real Property
§4(i)	Material GS Contracts
§4(j)	Litigation
§4(l)	Gathering System Permits
§4(m)	Environmental Matters
§4(n)	Insurance Policies
§4(u)	Relationships with Related Persons
§5(a)	Affected Employees
§5(b)(i)	Identified Employees
§5(c)(iv)	Employee Plans
§6(j)	Certain Actions by Sellers
§6(k)	VOC Emissions Sites
§6(m)	Radio Tower Facilities
§6(n)	Joint Use of Easements and Surface Sites

-v-

PURCHASE AGREEMENT

     This Purchase Agreement (this “Agreement”) is executed this 12th day of July, 2006 (the “Closing Date”), to be effective as of 12:01 a.m. July 1, 2006 (the “Effective Time”), by and between Cerrito Gathering Company, Ltd., a Texas limited partnership (“Cerrito”), Cerrito Gas Marketing, Ltd., a Texas limited partnership and a wholly-owned subsidiary of Cerrito (“CGM”), and Encinal Gathering, Ltd., a Texas limited partnership and a wholly-owned subsidiary of Cerrito (“EGL” and, together with Cerrito and CGM, “Sellers”), and Enterprise Products Partners L.P., a Delaware limited partnership (“Buyer”). Buyer, any Buyer Designee (as defined below), and each Seller are sometimes individually referred to as a “Party” and collectively as the “Parties.” Lewis Energy Group, L.P., a Delaware limited partnership (“LEG”), is executing this Agreement as guarantor of the obligations of Sellers hereunder, and for the limited purposes of making certain representations and disclaimers hereunder.

RECITALS

     WHEREAS, Sellers own an approximate 311 mile natural gas gathering system and related facilities and assets located in Webb, LaSalle and Dimmit Counties, Texas, generally known as the Cerrito Rich Gas Gathering System, which includes those assets described in §§2(a)(i), (iv), (v), (vi), (vii), (x) and (xi) of the Disclosure Schedule (but excluding the Excluded Assets, the “Gathering System”); and

     WHEREAS, Buyer desires to acquire from Sellers, and Sellers desire to sell to Buyer, on a going concern basis, substantially all the assets and properties which are owned by Sellers and relate to the Gathering System; and

     WHEREAS, Sellers and Buyer desire to enter into certain other related transactions as provided in this Agreement.

     Now, therefore, for and in consideration of the premises and the mutual promises made in this Agreement, and in consideration of the representations, warranties, and covenants contained in this Agreement, the Parties agree as follows:

§1. Definitions

     “Accredited Investor” has the meaning set forth in Rule 501(a) of Regulation D promulgated under the Securities Act.

     “Adverse Consequences” means all Proceedings, charges, complaints, claims, demands, injunctions, judgments, orders, decrees, rulings, damages, remedial obligations, dues, penalties, fines, costs, reasonable amounts paid in settlement, Liabilities, Taxes, Liens, losses, expenses, and fees, including court costs and reasonable attorneys’ fees and expenses.

     “Affected Employees” means all employees and independent contractors whose duties involve or directly relate to the operation of the Assets.

     “Affiliate” has the meaning set forth in Rule l2b-2 of the regulations promulgated under the Securities Exchange Act of 1934.

     “Applicable Rate” as to any given period means the rate for deposits of dollars for a period of 30 days at or about 11:00 a.m. (London time) on the second London banking day before the first day of the period for which such rate is required as displayed on Telerate page 3750 (British Bankers’ Association Interest Settlement Rates) (or such other page as may replace page 3750 on such system or on any other system of the information vendor for the time being designated by the British Bankers’ Association to calculate the British Bankers’ Association Interest Settlement Rate (as defined in the British Bankers’ Association’s Recommended Terms and Conditions, dated August, 1985)); provided that if on such date no such rate is so displayed, LIBOR for such period shall be the arithmetic mean (rounded upward if necessary to four decimal places) of the rates quoted by Citibank N.A. as its offered rate for deposits of dollars in an amount approximately equal to the amount in relation to which LIBOR is to be determined for a 30-day period to prime banks in the London Interbank Market at or about 11:00 a.m. (London time) on the second banking day before the first day of such period.

     “Assets” has the meaning set forth in §2(a).

     “Assumed Environmental Liabilities” means, subject to the last sentence of this paragraph, Liabilities for soil contamination, water contamination, and all other types of Releases or environmental damage or contamination in, on, around, or under the Assets or arising from the Assets including environmental contamination that exists as of the Closing Date or that is caused by or arises from Releases prior to, on, or after the Closing Date, regardless of whether such environmental contamination: (1) was known or unknown at the time of Closing Date; (2) was caused by the Seller Indemnified Parties or Third Persons’ pre-Closing negligence, actions, omissions, strict liability or fault; (3) gives rise to strict liability under any Environmental Laws or any applicable Laws; or (4) arises from the operation, design, physical condition, or maintenance-status of the Assets before on, or after the Closing Date. Notwithstanding the preceding, “Assumed Environmental Liabilities” do not include (a) any Liabilities that arise out of or relate to a Breach by any Seller or LEG of this Agreement or of any Transaction Document, (b) administrative, civil and/or criminal fines or penalties assessed by any Governmental Authority to the extent attributable to or assessed with respect to the period prior to Closing, Seller’s operation of the Assets, or the delay in obtaining Permits or approvals of Governmental Authorities required as of the Closing Date, (c) any Liabilities arising out of Proceedings involving property damage or personal injury that occurred prior to Closing; and/or (d) any Liabilities arising out of or relating to the Las Tiendas Remediation.

     “Assumed Liabilities” has the meaning set forth in §2(c)(i).

     “Base Purchase Price” means Three Hundred Twenty-Five Million Dollars ($325,000,000).

     “Basket” has the meaning set forth in §7(e).

     “Best Efforts” means the efforts, time, and costs that a prudent Person desirous of achieving a result would use, expend, or incur in similar circumstances to ensure that such result is achieved as expeditiously as possible.

-2-

     “Big Reef Treating Facility” means Cerrito’s gas treating facility located approximately 21 miles west/southwest of Encinal, Texas.

     “Bill of Sale” has the meaning set forth in §2(k)(i)(A).

     “Breach” means any breach of, or any inaccuracy in, any representation or warranty or any breach of, or failure to perform or comply with, any covenant or obligation, in or of this Agreement or any other Contracts, or any event which with the passing of time or the giving of notice, or both, would constitute such a breach, inaccuracy or failure.

     “Btu” or “British Thermal Unit” means the amount of heat required to raise the temperature of one pound of water from 58º Fahrenheit to 59º Fahrenheit under standardized conditions. It will be assumed that the gas is saturated with water vapor at 60º degrees Fahrenheit under a pressure of fourteen and seventy-three hundredths (14.73) psia, under standard gravitational force (980.665 centimeters per second squared).

     “Business Day” means any day that is not a Saturday, a Sunday, or other day on which national banks are closed in the City of Houston, Texas or in the City of New York, New York.

     “Buyer” has the meaning set forth in the preface.

     “Buyer Adverse Consequences” means the Adverse Consequences of the Buyer Indemnified Parties as to which the Buyer Indemnified Parties are entitled to indemnification under §7(a).

     “Buyer Designee” means any Affiliate of Buyer identified to Sellers.

     “Buyer Indemnified Parties” means Buyer and its Related Persons, each of their Representatives and each of the heirs, executors, successors and assigns of any of the preceding.

     “Canales 12” Gathering Line Assignment” has the meaning set forth in §2(k)(i)(D).

     “Cerrito” has the meaning set forth in the preface.

     “CGM” has the meaning set forth in the preface.

     “Claim for Indemnification” means a written notice by an Indemnified Party to the Indemnifying Party asserting a claim under §7 delivered in accordance with §8(g); provided, however, that such notice shall be sufficient if it provides a general description of the Adverse Consequences that the Indemnified Party may suffer, with an estimate of the extent of the dollar amount of Adverse Consequences.

     “Claims Period” means the period during which an Indemnified Party may assert a Claim for Indemnification.

     “Closing” has the meaning set forth in §2(j).

     “Closing Date” has the meaning set forth in the preface.

-3-

     “COBRA” means Consolidated Omnibus Budget Reconciliation Act, as amended.

     “Code” means the Internal Revenue Code of 1986, as amended.

     “Commission” has the meaning set forth in §6(f)(i).

     “Competing Business” has the meaning set forth in §4(u).

     “Condensate Inventory” means product of the volumes of condensate that Sellers own as of the Effective Time held in the facilities described in §1(a) of the Disclosure Schedule and verified by Representatives of Seller and Buyer together, multiplied by the posted price for Flint Hills Resources South Texas Light Sweet type crude oil, deemed 40 degrees API less Taxes, if any, plus $1.70 per barrel.

     “Confidentiality Agreement” means the terms of that certain confidentiality agreement between LEG and Enterprise Products Operating L.P. dated March 21, 2006.

     “Consent” means any unqualified approval, authorization, consent, ratification or waiver.

     “Contemplated Transactions” means all of the transactions contemplated in this Agreement.

     “Contract” means any agreement, contract, lease, consensual obligation, promise or undertaking (whether written or oral and whether express or implied).

     “Credit Facility” means the Fifth Amended and Restated Credit Agreement dated November 30, 2005 by and between Cerrito Gas Marketing, Ltd., Cerrito Gas Processing, LLC, Cerrito Gathering Company, Ltd., and Encinal Gathering, Ltd., as borrowers, the financial institutions party thereto as lenders, and Guaranty Bank as administrative agent and as issuing lender.

     “Deep Rich Gathering Agreement” means the gas gathering agreement, in the form of Exhibit A, for the gathering of gas produced from all depths deeper than one hundred (100) feet below the base of the Olmos Formation; provided that production from the Edwards Formation (as well as any other formations which produce gas containing either: (1) H₂S in concentrations greater than one-quarter (1/4) grain; or (2) CO₂ in concentrations greater than three percent (3%)) is excluded from this specific dedication.

     “Deep Rich Processing Agreement” means the gas processing agreement, in the form of Exhibit B, for the processing of gas produced from all depths deeper than one hundred (100) feet below the base of the Olmos Formation; provided that production from the Edwards Formation (as well as any other formations which produce gas containing either: (1) H₂S in concentrations greater than one-quarter (1/4) grain; or (2) CO₂ in concentrations greater than three percent (3%)) is excluded from this specific dedication.

     “Direct Costs” means the costs or expenses actually incurred by Sellers and their Affiliates to employees and Third Persons directly attributable to Transition Services, but

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excluding any overhead of Sellers and any overhead and/or profit components that might be charged to Sellers by their Affiliates.

     “Disclosure Schedule” has the meaning set forth in §4.

     “Dispute” has the meaning set forth in §8(i).

     “Easements” has the meaning set forth in §2(a)(xi).

     “Easements Assignment” has the meaning set forth in §2(k)(i)(G).

     “Edwards Formation” means the stratigraphic interval between the measured depths of 9,575 feet and 9,925 feet as seen in the LPP Booth WV Jr. “H” 5 U RRC #42-479-38866 located in Webb, Texas.

     “Effective Time” has the meaning set forth in the preface.

     “EGL” has the meaning set forth in the preface.

     “EH” means Enterprise Hydrocarbons L.P., a Delaware limited partnership.

     “Employee Plans” means, as provided by each Seller to its employees, all “employee benefit plans” as defined by Section 3(3) of ERISA, all specified fringe benefit plans as defined in Section 6039D of the Code, and all other bonus, incentive compensation, deferred compensation, profit-sharing, stock-option, stock appreciation-right, stock bonus, stock purchase, employee-stock-ownership, savings, severance, change-in-control, supplemental-unemployment, layoff, salary continuation, retirement, pension, health, life-insurance, disability, accident, group-insurance, vacation, holiday, sick-leave, fringe benefit or welfare plan, and any other employee compensation or benefit plan, Contract, policy, practice, commitment or understanding (whether qualified or nonqualified, currently effective or terminated, written or unwritten) and any trust, escrow or other Contract related thereto that: (1) is maintained or contributed to by such Seller or any other corporation or trade or business controlled by, controlling or under common control with such Seller (within the meaning of Section 414 of the Code or Section 4001(a)(14) or 4001(b) of ERISA) (“ERISA Affiliate”) or has been maintained or contributed to in the last six years by such Seller or any ERISA Affiliate, or with respect to which such Seller or any ERISA Affiliate has or may have any Liability; and (2) provides benefits, or describes policies or procedures applicable to any current or former director, officer, employee or service provider of Seller or any ERISA Affiliate, or the dependents of any thereof, regardless of how (or whether) Liabilities for the provision of benefits are accrued or assets are acquired or dedicated with respect to the funding thereof. Employee Plans include: (a) a “Defined Benefit Plan” (as defined in Section 414(l) of the Code); (b) a plan intended to meet the requirements of Section 401(a) of the Code; (c) a “Multiemployer Plan” (as defined in Section 3(37) of ERISA); or (d) a plan subject to Title IV of ERISA, other than a Multiemployer Plan.

     “Enterprise Products GP, LLC” is a Delaware limited liability company and the general partner of Buyer.

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     “Enterprise Texas Pipeline Lease” means the Lease Agreement between ETPL and EGL dated December 1, 2002.

     “Enterprise Texas Pipeline PSA” means the Purchase and Sale Agreement between ETPL and EGL dated December 1, 2005.

     “Enterprise Texas Pipeline PSA/Lease Termination Letter” means the letter agreement, to be dated the Closing Date, between ETPL and EGL terminating the Enterprise Texas Pipeline PSA and the Enterprise Texas Pipeline Lease in the form of Exhibit C.

     “Enterprise Texas Pipeline PSA/Lease Termination Payment” means Two Hundred Seventy-Five Thousand Dollars ($275,000), which is the amount that EGL owes ETPL in consideration for termination of the Enterprise Texas Pipeline PSA and the Enterprise Texas Pipeline Lease as provided in the Enterprise Texas Pipeline PSA/Lease Termination Letter.

     “Enterprise Units” means Common Units of Buyer as such term is defined in the Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Product Partners L.P., dated August 8, 2005.

     “Environmental Law” means any and all Laws pertaining to the protection of the environment or natural resources or to Hazardous Materials in any and all jurisdictions in which any Seller owns property or conducts business or in which the Assets are located, including the Clean Air Act, the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), the Federal Water Pollution Control Act, the Occupational Safety and Health Act of 1970 (to the extent relating to environmental matters), the Resource Conservation and Recovery Act of 1976, the Safe Drinking Water Act, the Toxic Substances Control Act, the Hazardous & Solid Waste Amendments Act of 1984, the Superfund Amendments and Reauthorization Act of 1986, the Hazardous Materials Transportation Act, the Oil Pollution Act of 1990, any state or local Laws implementing or substantially equivalent to the foregoing federal Laws, and any state or local Laws pertaining to the handling of oil and gas exploration, production, gathering, and processing wastes or the use, maintenance, and closure of pits and impoundments, all as amended through the Closing Date.

     “Equipment” has the meaning set forth in §2(a)(vi).

     “ERISA” means the Employee Retirement Income Security Act of 1974, as amended.

     “ESTG” means Enterprise South Texas Gathering L.P., a Delaware limited partnership.

     “Estimated Purchase Price” has the meaning set forth in §2(d).

     “ETPL” means Enterprise Texas Pipeline L.P., a Delaware limited partnership.

     “Excluded Assets” has the meaning set forth in §2(b).

     “Excluded Liabilities” means the Liabilities set forth in §2(c)(ii).

     “Final Purchase Price” has the meaning set forth in §2(f).

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     “Final Settlement Date” has the meaning set forth in §2(f).

     “GAAP” means generally accepted accounting principles in the United States.

     “Gathering Lines” has the meaning set forth in §2(a)(v).

     “Gathering Lines Assignment” has the meaning set forth in §2(k)(i)(C).

     “Gathering System” has the meaning set forth in the recitals.

     “Gathering System Contracts” has the meaning set forth in §2(a)(ii).

     “Gathering System Contracts Assignment” has the meaning set forth in §2(k)(i)(F).

     “Gathering System Permits” has the meaning set forth in §2(a)(iii).

     “Gathering System Permits Assignment” has the meaning set forth in §2(k)(i)(E).

     “General Exceptions to Enforceability” means limitations on or exceptions to the enforceability of a Contract or instrument by: (1) bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium, or other similar Laws affecting creditors’ rights; or (2) general principles of equity relating to the availability of equitable remedies (regardless of whether such Contract or instrument is sought to be enforced in a Proceeding at Law or in equity).

     “Governing Documents” means, with respect to any particular entity: (1) if a corporation, the articles or certificate of incorporation and the bylaws; (2) if a general partnership, the partnership agreement and any statement of partnership; (3) if a limited partnership, the limited partnership agreement and the certificate of limited partnership; (4) if a limited liability company, the articles of organization and operating agreement; (5) if another type of Person, any other charter or similar document adopted or filed in connection with the creation, formation or organization of the Person; (6) all equityholders’ agreements, voting agreements, voting trust agreements, joint venture agreements, registration rights agreements or other agreements or documents relating to the organization, management or operation of any Person or relating to the rights, duties and obligations of the equityholders of any Person; and (7) any amendment or supplement to any of the foregoing.

     “Governmental Authority” means: (1) the United States of America or any state or local political subdivision thereof within the United States of America; (2) any court or any governmental or administrative department, commission, board, bureau, or agency of the United States of America or of any state or local political subdivision thereof within the United States of America; and (3) any national, state, regional, or local government, regulatory or administrative authority, any subdivision, agency, commission in or authority thereof, including any quasi-governmental organization, any court, tribunal or arbitral body acting within its legal authority.

     “Hazardous Materials” means: (1) any chemicals, materials or substances listed as or defined or included in the definition of “hazardous substance,” “hazardous material,” “toxic substance,” “solid waste,” “pollutant,” “contaminant,” or words of similar import, under any applicable Environmental Law; and (2) radioactive materials, asbestos, mercury, lead based

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paints, polychlorinated biphenyls, and any waste or spilled petroleum (including, crude oil or any faction thereof), petroleum products, natural gas liquids, or natural gas condensate.

     “Houston Ship Channel Index” means the index price listed in the first regular edition of Platts Inside FERC Gas Market Report published during the Month of delivery and identified in the table entitled “MARKET CENTER SPOT-GAS PRICES” under the heading “East Texas” as the “Houston Ship Channel” price under the column entitled “Index.”

     “HPLC” means Houston Pipe Line Company LP.

     “HPLC Gas Purchase Agreement” means that certain Gas Purchase Agreement between HPLC and CGM dated effective August 1, 2005, as amended by the First Amendment to Gas Purchase Agreement dated October 1, 2005.

     “HSR Act” means the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended.

     “Identified Employees” has the meaning set forth in §5(b)(i).

     “Imbalance Payable” shall mean the value of any volumetric imbalance owed by Sellers to any Affiliate of Buyer as of the Effective Time based upon 99% of the Houston Ship Channel Index as of the Effective Time less $.025/MMBtu.

     “Imbalance Receivable” shall mean the value of any volumetric imbalance owed by any Affiliate of Buyer to Sellers as of the Effective Time based upon 99% of the Houston Ship Channel Index as of the Effective Time less $.025/MMBtu.

     “Imbalances” means all natural gas imbalances between any Seller and a Third Person relating to or arising out of the operation of the Assets that exist at the Effective Time.

     “Indebtedness” means any financing encumbering any Asset that is a Liability of any Seller or any Affiliate of Seller, which has been paid off or otherwise released as of Closing, including the Credit Facility and those listed on §1(b) of the Disclosure Schedule.

     “Indefinite Surviving Representations” means the following representations and warranties: §4(a) (Organization, Qualification, and Power), §4(b) (Authorization of Transaction), §4(c) (Non-contravention), §4(d) (Brokers’ Fees), §4(e)(i) (Assets), §4(h)(i) (Title to Real Property), §4(r) (No Other Agreements to Sell Assets), §4(t) (Sellers’ Private Placement Representations), §4(u) (Relationships with Related Persons), and §4(y) (Indebtedness).

     “Indemnification Cap” has the meaning set forth in §7(e).

     “Indemnified Party” means a Buyer Indemnified Party or a Seller Indemnified Party.

     “Indemnifying Party” means the Party providing indemnification to the Indemnified Party.

     “Independent Accounting Firm” has the meaning set forth in §2(f).

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     “Interim Excluded Assets” means the assets and properties described in §1(c) of the Disclosure Schedule.

     “Knowledge of Buyer” means actual knowledge after reasonable inquiry, of each individual listed in §1(d) of the Disclosure Schedule.

     “Knowledge of Seller or Sellers” means actual knowledge after reasonable inquiry, of each individual listed in §1(e) of the Disclosure Schedule.

     “Lawful Assign” has the meaning set forth in §6(g).

     “Las Tiendas Remediation” means the remediation activities of Sellers at the Las Tiendas site, a 200’ x 400’ fenced site located approximately 21 miles southwest of Encinal in Webb County, Texas, located at approximate latitude N27° 53’51” and longitude W99° 39’15”, pursuant to a site remediation plan and agreement between Cerrito, HPLC and the Railroad Commission of Texas.

     “Laws” means all applicable statutes, laws (including common law), regulations, rules, rulings, ordinances, orders, restrictions, requirements, writs, judgments, injunctions, decrees and other official acts of or by any Governmental Authority or arbitral body.

     “Lean Gas Gathering Agreement” means the Contract for the gathering and transportation of lean gas from the Big Reef Treating Facility, in the form of Exhibit D.

     “LEG” has the meaning set forth in the preface.

     “Lehman” means Lehman Brothers, Inc.

     “Liability” means any liability or obligation (whether known or unknown, whether asserted or unasserted, whether absolute or contingent, whether accrued or unaccrued, whether liquidated or unliquidated, and whether due or to become due), including those arising under any Law and those arising under any Contract or undertaking, and whether or not the same is required to be accrued on the financial statements of any Person.

     “Lien” means any charge, claim, community or other marital property interest, condition, equitable interest, lien, option, pledge, security interest, mortgage, right of way, easement, encroachment, servitude, right of first option, right of first refusal or similar restriction, including any restriction on use, voting (in the case of any security or equity interest), transfer, receipt of income or exercise of any other attribute of ownership.

     “Lock-Up Period” has the meaning set forth in §6(g).

     “LPP” means Lewis Petro Properties, Inc.

     “LPP Zero Rate Gathering Service Letter Agreement” means the letter agreement, in the form of Exhibit E, under which LPP will provide, subject to certain conditions, zero rate gathering service to EH for Third Persons’ gas.

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     “Material Adverse Effect” or “Material Adverse Change” means any effect, event, combination of events, circumstance, occurrence, or change that, individually or in the aggregate, is or could reasonably be expected to be materially adverse to the Gathering System or the Assets, taken as a whole, or to the ability of any Party to consummate timely the Contemplated Transactions; provided that none of the following shall be deemed to constitute, and none of the following shall be taken into account in determining whether there has been, a Material Adverse Effect or Material Adverse Change: any adverse change, event, development, or effect arising from or relating to: (1) general business or economic conditions; (2) national or international political or social conditions, including the engagement-or continuation by the United States in hostilities, whether or not pursuant to the declaration of a national emergency or war, or the occurrence of any military or terrorist attack upon the United States, or any of its territories, possessions, or diplomatic or consular offices or upon any military installation, equipment or personnel of the United States; or (3) financial, banking, or securities markets (including any disruption thereof and any decline in the price of any security, commodity or market index); provided that none of the changes, events, developments or effects described in clauses (1) through (3) specifically relate to or have the effect of specifically relating to or having a materially disproportionate effect on the Gathering System or the Assets relative to most other industry participants in the midstream natural gas industry. For purposes hereof, any reference to “Material Adverse Effect” in any representation or warranty contained in §4 of this Agreement shall be deemed to include any event, combination of events, circumstance or occurrence or change that, individually or in the aggregate, has or could reasonably be expected to result in Adverse Consequences in excess of Five Hundred Thousand Dollars ($500,000).

     “Material Consents” means all Consents from Persons other than Governmental Authorities that are listed in §1(f) of the Disclosure Schedule.

     “Material GS Contracts” has the meaning set forth in §4(i).

     “Mexico Gathering Agreement” means the Mexican gas gathering agreement between EGL and EH, in the form of Exhibit F.

     “Mexico Processing Agreement” means the Mexican gas processing agreement between EGL and EH, in the form of Exhibit G.

     “Non-Circumvention Agreement” means the Non-Circumvention Agreement in the form of Exhibit H, pursuant to which Buyer and/or its Affiliates agree not to circumvent LEG’s acquisition of gas from Petroleos Mexicanos.

     “Non-Material Consents” has the meaning set forth in §2(l)(ii).

     “Notice” has the meaning set forth in §8(g).

     “Olmos Formation” means the stratigraphic interval between the measured depths of 6,490 feet and 6,881 feet as seen in the LLP Beasley State 97 #26 (API #42-479-39424) located in Webb County, Texas.

     “Ordinary Course of Business” means the ordinary course of business consistent with past custom and practice (including with respect to quantity and frequency).

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     “Owned Real Property” has the meaning set forth in §2(a)(x).

     “Parent Guarantee” means the guaranty in the form of Exhibit I, under which LEG guarantees Sellers’ obligations with respect to the Contemplated Transactions.

     “Parts Inventory” has the meaning set forth in §2(a)(vii).

     “Party” or “Parties” has the meaning set forth in the preface.

     “Permits” means all permits, licenses, certificates, orders, approvals, authorizations, registrations, grants, Consents, concessions, warrants, franchises, and similar rights and privileges granted by a Governmental Authority.

     “Permits Assignment” has the meaning set forth in §2(k)(i)(E).

     “Permitted Encumbrances” means: (1) real estate Taxes, assessments and other levies, fees, or charges imposed by a Governmental Authority that are (a) not due and payable as of the Closing Date, or (b) being contested in good faith by appropriate Proceedings; (2) any Lien consisting of (i) rights reserved to or vested in any Governmental Authority to control or regulate any Asset or to limit the use of such Asset in any manner which does not materially impair the use of such Asset for the purposes for which it is held by Sellers, or (ii) obligations or duties to any Governmental Authority with respect to any Permit relating to any period after Closing and the rights reserved or vested in any Governmental Authority to terminate any such Permit or to condemn or expropriate any property; (3) mechanics Liens and similar Liens for labor, materials, or supplies provided with respect to Assets incurred prior to the Effective Time and in the Ordinary Course of Business for amounts that are (A) not delinquent and would not, or would not reasonably be expected to, in the aggregate, be material to the Assets or the Gathering System, or (B) being contested in good faith by appropriate Proceedings; (4) zoning, building codes, and other land use Laws regulating the use or occupancy of Owned Real Property or the activities conducted thereon that are imposed by any Governmental Authority having jurisdiction over such Owned Real Property; and (5) easements, servitudes, rights-of-way, covenants, conditions, restrictions, and other similar matters affecting title to the Assets and other title defects that, singularly or in the aggregate, do not or would not interfere with the present or proposed ownership, use or operation of the Assets to which those matters relate and which are of a nature that would be reasonably acceptable to a prudent pipeline operator.

     “Person” means an individual, a partnership, a corporation, a limited liability company, an association, a joint stock company, a trust, a joint venture, an unincorporated organization, any other business entity or a Governmental Authority (including any department, agency, or political subdivision thereof).

     “Personal Property” has the meaning set forth in §2(a)(iv).

     “Plant Facilities” has the meaning set forth in §2(a)(i).

     “Post-Closing Settlement Statement” has the meaning set forth in §2(f).

     “Preliminary Settlement Statement” has the meaning set forth in §2(e).

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     “Proceeding” means any action, suit, claim, investigation, review, or other judicial or administrative proceeding, at Law or in equity, before or by any Governmental Authority or arbitration or other dispute resolution Proceeding.

     “Prudent Industry Practices” means at a particular time, any of the practices, methods and acts which, in the exercise of reasonable judgment, will result in the proper operation and maintenance of the Assets and shall include the practices, methods and acts engaged in or approved by a significant portion of the industry at such time with respect to assets of the same or similar types as the Assets. Prudent Industry Practices is not intended to be limited to the optimum practice, method or act, to the exclusion of all others, but rather is a spectrum of possible practices, methods and acts which could have been expected to accomplish the desired result at a commercially reasonably cost consistent with reliability, safety, timeliness, and all applicable Laws and Environmental Law. Prudent Industry Practices is intended to mean at least the same standard as the Parties would, in the prudent management of their own properties, use from time to time.

     “Qualified Beneficiaries” has the meaning set forth in §5(d).

     “Records” has the meaning set forth in §2(a)(ix).

     “Registrable Securities” has the meaning set forth in §6(f)(i).

     “Related Person” means, with respect to a particular individual:

     (a) each other member of such individual’s family;

     (b) any Person that is directly or indirectly controlled by any one or more members of such individual’s family;

     (c) any Person in which members of such individual’s Family hold (individually or in the aggregate) a material interest; and

     (d) any Person with respect to which one or more members of such individual’s family serves as a director, officer, partner, executor or trustee (or in a similar capacity).

With respect to a specified Person other than an individual:

     (e) any Person that directly or indirectly controls, is directly or indirectly controlled by or is directly or indirectly under common control with such specified Person;

     (f) any Person that holds a material interest in such specified Person;

     (g) each Person that serves as a director, officer, partner, executor or trustee of such specified Person (or in a similar capacity);

     (h) any Person in which such specified Person holds a material interest; and

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     (i) any Person with respect to which such specified Person serves as a general partner or a trustee (or in a similar capacity).

     For purposes of this definition: (1) “control” (including “controlling,” “controlled by,” and “under common control with”) means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through the ownership of voting securities, by contract or otherwise, and shall be construed as such term is used in the rules promulgated under the Securities Act; (2) the “family” of an individual includes (a) the individual, (b) the individual’s spouse, (c) any other natural person who is related to the individual or the individual’s spouse within the second degree and (d) any other natural person who resides with such individual; and (3) “material interest” means direct or indirect beneficial ownership (as defined in Rule 13d-3 under the Securities Exchange Act of 1934) of voting securities or other voting interests representing at least 10% of the outstanding voting power of a Person or equity securities or other equity interests representing at least 10% of the outstanding equity securities or equity interests in a Person.

     “Release” means any spilling, leaking, pumping, pouring, emitting, emptying, discharging, injecting, escaping, leaching, dumping, or disposing of Hazardous Materials into or upon the environment (including the abandonment or discarding of barrels, containers, and other closed receptacles containing any Hazardous Material and which are not empty as defined by 40 C.F.R. §261.7(b)).

     “Representative” means, with respect to a particular Person, any director, officer, manager, employee, agent, consultant, advisor, accountant, financial advisor, legal counsel, lender, insurer or other representative of that Person.

     “Restricted Material GS Contracts” has the meaning set forth in §2(l)(i).

     “Restricted Non-Material GS Contracts” has the meaning set forth in §2(l)(ii).

     “Securities Act” means the Securities Act of 1933, as amended.

     “Seller” or “Sellers” has the meaning set forth in preface.

     “Seller Adverse Consequences” means the Adverse Consequences of the Seller Indemnified Parties as to which the Seller Indemnified Parties are entitled to indemnification under §7(b).

     “Seller Indemnified Parties” means Sellers and their respective Representatives and Related Persons and each of the heirs, executors, successors and assigns of any of the preceding.

     “Seller Representative” has the meaning set forth in §8(k)

     “Service Standard” means, with respect to the standard of performance for the Transition Services performed or caused to be performed, the good-faith undertaking, on a commercially reasonable basis, to perform the Transition Services: (1) in at least the same quality and manner as the same or comparable services were provided by Sellers and Sellers’ Affiliates before the

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Effective Time; and (2) in all material respects in compliance with all applicable Laws, Environmental Law and Prudent Industry Practices.

     “Shallow Rich Gathering Agreement” means the gas gathering agreement, in the form of Exhibit J, for the gathering of gas produced from all depths shallower than one hundred (100) feet below the base of the Olmos Formation.

     “Shallow Rich Processing Agreement” means the gas processing agreement, in the form of Exhibit K, for the processing of gas produced from all depths shallower than one hundred (100) feet below the base of the Olmos Formation.

     “Shelf Registration Notice” has the meaning set forth in §6(f)(iii).

     “Shelf Registration Statement” has the meaning set forth in §6(f)(i).

     “Special Warranty Deed” has the meaning set forth in §2(k)(i)(B).

     “Surviving Indemnification Obligations” means the indemnification obligations described in §7(a)(ii), §7(a)(iii), §7(a)(iv) and §7(a)(v).

     “Tax” or “Taxes” means any federal, state, local, or foreign income, gross receipts, license, payroll, employment, excise, severance, stamp, occupation, premium, windfall profits, environmental (including Taxes under Code §59A), customs duties, capital stock, franchise, profits, withholding, social security (or similar), unemployment, disability, real property, personal property, sales, use, transfer, registration, value added, ad valorem, alternative or add-on minimum, estimated, or other tax of any kind whatsoever, including any interest, penalty, or addition thereto, whether disputed or not.

     “Tax Return” means any return, declaration, report, claim for refund, or information return or statement relating to Taxes, including any schedule or attachment thereto, and including any amendment thereof.

     “Tercero Navarro” means Tercero Navarro, Inc., a Delaware corporation and the general partner of each of the Sellers.

     “Third Person” means any Person other than Sellers or Buyer.

     “Transaction Documents” means all Contracts, other than this Agreement, and the deeds, instruments and assignments required to be entered into and delivered under this Agreement.

     “Transfer Date” has the meaning set forth in §5(b)(iii).

     “Transferred Employee” means any Affected Employee who accepts Buyer’s offer of employment.

     “Transition Services” has the meaning set forth in §6(d).

     “Unit Closing Price” has the meaning set forth in §2(d).

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     “Violation” has the meaning set forth in §6(f)(v)(A).

     “VOC” means volatile organic compounds, excluding methane and ethane.

     “VOC Holdback Amount” means the sum of One Million Seven Hundred and Fifty Thousand Dollars ($1,750,000).

§2. Purchase and Sale of Assets

     (a) Assets. On the terms and subject to the conditions of this Agreement and effective for all purposes as of the Effective Time, at Closing, Buyer agrees to purchase, on a going concern basis from Sellers, and Sellers agree to sell, transfer and deliver to Buyer (or one or more Buyer Designees), free and clear of all Liens (other than Permitted Encumbrances), all right, title, and interest in and to the assets properties, rights, licenses, Contracts, and business, of every kind and description, wherever located, real, personal or mixed, tangible or intangible, owned, held or used in the operation of the Gathering System by Sellers as the same exists on the Closing Date, excluding the Excluded Assets (collectively, the “Assets”), and including all right, title and interest in, to and under:

     (i) the gas processing plants, treaters, dehydration units, condensate storage tanks, compressor stations, warehouses, field offices, control buildings and other associated plant facilities which are part of the Gathering System, which are described in §2(a)(i) of the Disclosure Schedule (collectively, the “Plant Facilities”);

     (ii) the Contracts of any kind that relate to the Gathering System and to which any Seller or any of its Affiliates is a party, including all Contracts under which any Seller is providing gas gathering and/or processing services to Third Persons, which Contracts are listed in §2(a)(ii) of the Disclosure Schedule (the “Gathering System Contracts”);

     (iii) to the extent assignable to Buyer, the Permits required or necessary for Sellers to own and operate the Gathering System in the places and in the manner currently owned or operated or otherwise necessary to operate the Gathering System as it is currently operated, which are listed in §2(a)(iii) of the Disclosure Schedule (the “Gathering System Permits”);

     (iv) the personal property and interests therein, necessary for, used or held for use in connection with the Gathering System, including all machinery, furniture, office equipment, communications equipment, radios, vehicles, replacement parts, fuel and other trade fixtures, fixed assets and other tangible personal property, which are listed in §2(a)(iv) of the Disclosure Schedule, and all hydrocarbon inventory of the Gathering System, including linefill (collectively, the “Personal Property”);

     (v) the natural gas gathering pipelines, residue gas pipelines and other gas pipelines comprising the Gathering System, which are described in §2(a)(v) of the Disclosure Schedule (the “Gathering Lines”);

     (vi) the fixtures, pipes, drips, valves, fittings, connections, regulators, compressors, cathodic or electric protection units, gates, meters, measuring stations,

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meter and regulatory houses, other meter and regulation equipment, instruments, tanks, storage facilities, expanders, dehydrators, heaters, heat exchangers, chillers, separators, pumps, coolers, cooling towers, boilers, re-boilers, turbines, engines, generators, trucks, automobiles, and other equipment related to or comprising a part of the Gathering Lines or the Plant Facilities and all improvements, fixtures and appurtenances thereto used in the operation of the Gathering System, which are described in §2(a)(vi) of the Disclosure Schedule (the “Equipment”);

     (vii) the spare parts, pipe, valves and other similar items of inventory located on or about the Gathering Lines and the Plant Facilities and intended for use in connection with the Gathering System (the “Parts Inventory”);

     (viii) the natural gas, condensate and other hydrocarbons owned by Sellers and located in the Gathering Lines, the Plant Facilities, the Equipment or elsewhere in the Gathering System as of the Closing Date, including linefill;

     (ix) the contract, land, title, engineering, environmental, operating, accounting, business, marketing, and other data, files, documents, instruments, notes, papers, ledgers, journals, reports, abstracts, surveys, maps, keys, lock combinations, computer access codes and similar information, books, records and studies which relate to the Gathering System and/or the Assets or which are used, useful, or held for use in connection with, the ownership, operation or maintenance of the Gathering System and the Assets, including all of the same necessary to cause operations to remain in compliance with applicable Law, including Environmental Law (collectively, the “Records”);

     (x) the lands and other surface estates described in §2(a)(x) of the Disclosure Schedule (collectively, the “Owned Real Property”), and all appurtenances, Easements and other rights, buildings and other improvements thereto or thereon not otherwise described in this §2(a);

     (xi) the easements, rights-of-way, surface use agreements, servitudes, licenses, Permits and other similar rights for the use of the surface or subsurface estate in connection with the Gathering System, which are described in §2(a)(xi) of the Disclosure Schedule (the “Easements”);

     (xii) the benefit of all prepaids, deferred costs, deposits, advances, credits and expenses that have been prepaid by Sellers to the extent relating to the Gathering System including, lease and rental payments; and

     (xiii) all of Sellers’ rights, claims, counterclaims, credits, causes of action, lawsuits, judgments, demands or rights of set-off against third parties relating to the Gathering System or the Assets, including unliquidated rights under manufacturers’ and vendors’ warranties and all rights in and under any express or implied guarantees, warranties, representations, covenants, indemnities and similar rights in favor of any Seller.

In §2(a)(i) through §2(a)(xiii) of the Disclosure Schedule, Sellers shall, where applicable, identify the owner of each of the Assets and the locations of all physical Assets.

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     (b) Excluded Assets. Buyer and Sellers agree that the following assets and properties of Sellers related to the Gathering System or the Assets, as applicable, will be retained by Sellers and are excluded from the Gathering System and the Assets (the “Excluded Assets”):

     (i) all deposits, cash, checks, funds and accounts receivable and other rights to payment arising from or relating to the operation of the sale and transportation of natural gas and natural gas condensate with respect to any period of time prior to the Effective Time, including all Imbalance Receivables;

     (ii) any Personal Property that is sold or consumed by Sellers prior to Closing in the Ordinary Course of Business;

     (iii) each Seller’s Governing Documents;

     (iv) any Seller’s contracts of insurance and any Seller’s employee benefit agreements, plans, arrangements and policies, and any assets related thereto;

     (v) the rights that accrue to Sellers under this Agreement;

     (vi) the assets and properties described in §2(b)(vi) of the Disclosure Schedule; and

     (vii) the Interim Excluded Assets, until they are transferred to and accepted by ESTG.

     (c) Liabilities.

     (i) Subject to §6(e), effective as of the close of business on the Closing Date, Buyer (or one or more Buyer designees) shall assume and agree to pay, discharge or perform, as appropriate: (1) the Liabilities of Sellers under the Gathering System Contracts, Easements, and Gathering System Permits to the extent those Liabilities are not required to be performed prior to the Closing Date, do not arise out of or relate to a Breach that occurred prior to the Closing Date, are disclosed on the face of such documents, and accrue and relate to the operations of the Gathering System after the Closing Date; (2) any Liabilities arising out of and attributable to the operation of the Gathering System and the Assets after the Closing Date; (3) the Assumed Environmental Liabilities; and (4) any Liabilities arising out of and attributable to the operation of the Interim Excluded Assets after they have been transferred to ESTG or another Buyer Designee, and that Person has accepted the Interim Excluded Assets as provided under §6(l) (those Liabilities, collectively the “Assumed Liabilities”).

     (ii) Notwithstanding any provision in this Agreement or any other writing to the contrary, Buyer is assuming only the Assumed Liabilities and is not assuming any other Liability of Sellers or their Affiliates. All such other Liabilities will remain Liabilities of Sellers and/or their Affiliates (those Liabilities not being assumed by Buyer, the “Excluded Liabilities”).

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     (d) Estimated Purchase Price. At Closing, Buyer agrees to pay to Sellers the Base Purchase Price for the Assets, adjusted up or down by: (1) the estimated net difference of the Imbalance Receivables and Imbalance Payables; (2) the value of all Condensate Inventory; (3) accounts receivable and accounts payable existing as of the Effective Time under operating Contracts between Affiliates of the Parties; (4) prorated ad valorem taxes; (5) the Enterprise Texas Pipeline PSA/Lease Termination Payment (the Base Purchase Price, as adjusted, the “Estimated Purchase Price”), payable in cash and Enterprise Units; and (6) the VOC Holdback Amount. The Estimated Purchase Price allocation between cash and Enterprise Units is set forth on §2(d) of the Disclosure Schedule. The number of Enterprise Units shall be determined by dividing that portion of the Estimated Purchase Price payable in Enterprise Units by the Unit Closing Price (hereafter defined); provided, if the number so determined contains a fraction, such number shall be rounded upward to the nearest whole number. “Unit Closing Price” means the average closing price of Enterprise Units on the New York Stock Exchange over the ten consecutive trading days prior to the Closing Date.

     (e) Preliminary Settlement Statement. Attached as §2(e) of the Disclosure Schedule is a written statement of the Parties’ calculation of the Estimated Purchase Price based on information available to Parties as of the Closing Date (the “Preliminary Settlement Statement”). The Preliminary Settlement Statement includes wire transfer instructions for the Closing payments to be made to Cerrito

     (f) Post-Closing Adjustment Procedure. The Parties acknowledge that as of the Effective Time, the Gathering System may be subject to Imbalances. Sellers shall use reasonable efforts to minimize the extent of the Imbalances. Buyer shall use reasonable efforts to prepare and deliver to the Seller Representative, as soon as practicable but no later than 30 days after the Closing Date, in accordance with this Agreement and GAAP, a statement (the “Post-Closing Settlement Statement”) setting forth any changes to the Pre-Closing Settlement Statement, each adjustment or payment that was not finally determined as of the Closing Date, the calculation of such adjustments and a proposed final purchase price, which will include interest from and including the Effective Time to, but excluding, the Closing Date, at the Applicable Rate calculated on the basis of a 365-day year (the “Final Purchase Price”). Within 15 days after receipt of the Post-Closing Settlement Statement, the Seller Representative shall deliver to Buyer a written report containing any changes that Sellers propose be made to the Post-Closing Settlement Statement. The Parties shall undertake to agree to the Final Purchase Price and any amounts due pursuant to such post-closing adjustment no later than 15 days after Buyer has received Sellers’ proposed changes. If Buyer and Sellers cannot agree on the Post-Closing Settlement Statement within 60 days after the Closing Date, the Parties shall engage an internationally recognized public accounting firm acceptable to Buyer and Sellers (the “Independent Accounting Firm”), to resolve any disputed amounts (and only those amounts). Buyer, on the one hand, and Sellers, on the other hand, each must pay one half of the fees and other costs of the Independent Accounting Firm. If the Parties engage the Independent Accounting Firm under this §2(f), Sellers and Buyer shall provide the Independent Accounting Firm with a detailed statement itemizing any disputed amounts and all records and other information relevant to the determination of the amounts. The Parties shall instruct the Independent Accounting Firm to make those calculations as soon as practicable. The final determination of any of the disputed items as calculated under this §2(f) is binding on the Parties. The date upon which such agreement is reached or upon which the Final Purchase Price is

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established shall be called the “Final Settlement Date.” If the Final Purchase Price is more than the Estimated Purchase Price, Buyer will pay in immediately available funds the amount of that difference to Sellers or to Sellers’ account (as designated by the Seller Representative). If the Final Purchase Price is less than the Estimated Purchase Price, Sellers will pay in immediately available funds the amount of that difference to Buyer or to Buyer’s account (as designated by Buyer). Buyer or Sellers, as the case may be, shall pay the amount of the difference within five Business Days after the Final Settlement Date.

     (g) Final Purchase Price Allocation. Once the Final Purchase Price is determined, Sellers and Buyer agree that the Final Purchase Price will be allocated to the Assets for Tax and financial accounting purposes by Ernst & Young LLP, within 120 days after Final Settlement Date. Sellers and Buyer agree: (1) to report the federal, state and local income and other Tax consequences of the Contemplated Transactions, and in particular to report the information required by Section 1060(b) of the Code, and to jointly prepare Form 8594 (Asset Acquisition Statement under Section 1060) in a manner consistent with such allocation; and (2) without the Consent of the other Party, not to take any position inconsistent therewith upon examination of any Tax return, in any refund claim, in any litigation, investigation or otherwise. Sellers and Buyer agree that each will furnish the other a copy of Form 8594 (Asset Acquisition Statement under Section 1060) proposed to be filed with the Internal Revenue Service by such Party or any Affiliate thereof within ten days prior to the filing of such form with the Internal Revenue Service. No later than August 31, 2006, Sellers shall notify Buyer of Sellers’ Tax basis in the Assets.

     (h) Sellers’ Liability for Taxes. Sellers will be responsible for paying, or reimbursing Buyer for the payment of, all ad valorem, property, production, severance and similar Taxes and assessments based upon or measured by the ownership of property or the production of hydrocarbons or the receipt of proceeds therefrom accruing to the Assets prior to the Effective Time.

     (i) Prorations. With respect to amounts subject to pro-ration under this Agreement, if actual figures are not available at the Closing Date, the proration will be based upon the amounts accrued through the Effective Time or paid for the most recent year (or other appropriate period) for which actual amounts paid are available. Such prorated amounts will be re-prorated and paid to the appropriate Party within 60 days after the date that the previously unavailable actual figures become available. The prorations will be based on the number of days in a year or other appropriate period before and after the Effective Time. Sellers and Buyer agree to furnish each other with such documents and other records as may be reasonably requested in order to confirm all adjustment and proration calculations made under this Agreement.

     (j) Closing. The closing of the Contemplated Transactions (the “Closing”) will take place at the offices of King & Spalding in Houston, Texas, simultaneously with the Parties’ execution and delivery of this Agreement and the execution and delivery of the Transaction Documents by the parties to the Transaction Documents. At Closing, Buyer will purchase the Assets from Sellers and simultaneously contribute such Assets to the Buyer Designees by way of direct assignment from Sellers to such Buyer Designees as provided in this Agreement.

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     (k) Closing Obligations. In addition to any other documents to be delivered under other provisions of this Agreement, at Closing:

     (i) Sellers or LEG, as applicable, shall deliver to Buyer, the following:

     (A) an executed counterpart from Sellers of a Bill of Sale covering the Assets in the form attached hereto as Exhibit L (the “Bill of Sale”);

     (B) an executed counterpart from Cerrito of a special warranty deed covering the Owned Real Property in the form of Exhibit M (the “Special Warranty Deed”);

     (C) an executed counterpart from Cerrito and EGL of the Assignment and Bill of Sale of the Gathering Lines in the form of Exhibit N (the “Gathering Lines Assignment”);

     (D) an executed counterpart from Cerrito of the Assignment and Bill of Sale of the Canales 12” Gathering Line in the form of Exhibit O (the “Canales 12” Gathering Line Assignment”);

     (E) an executed counterpart from Cerrito and EGL of the Assignment and Assumption of Gathering System Permits in the form of Exhibit P, which assignment also contains Buyer’s undertaking and assumption of the Assumed Liabilities relating to the Gathering System Permits (the “Gathering System Permits Assignment”);

     (F) an executed counterpart from CGL of an Assignment and Assumption of the Gathering System Contracts in the form of Exhibit Q, which assignment also contains Buyer’s undertaking and assumption of the Assumed Liabilities relating to the Gathering System Contracts (the “Gathering System Contracts Assignment”);

     (G) an executed counterpart from Cerrito and EGL of an Assignment and Assumption of Easements in the form of Exhibit R, which assignment will also contain Buyer’s undertaking and assumption of the Assumed Liabilities relating to the Easements (the “Easements Assignment”);

     (H) such other deeds, bills of sale, assignments, certificates of title, affidavits, indemnity agreements, closing statements, cross receipts, documents, and other instruments as Buyer may reasonably request in order to consummate the Contemplated Transactions;

     (I) an executed counterpart from LPP of the Shallow Rich Gathering Agreement;

     (J) an executed counterpart from LPP of the Shallow Rich Processing Agreement;

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     (K) an executed counterpart from LPP of the Deep Rich Gathering Agreement;

     (L) an executed counterpart from LPP of the Deep Rich Processing Agreement;

     (M) an executed counterpart from EGL of the Lean Gas Gathering Agreement;

     (N) an executed counterpart from EGL of the Mexico Gathering Agreement;

     (O) an executed counterpart from EGL of the Mexico Processing Agreement;

     (P) an executed counterpart from EGL of the Enterprise Texas Pipeline PSA/Lease Termination Letter;

     (Q) a certificate of good standing, existence, or similar document with respect to Tercero Navarro and each Seller issued by the appropriate Governmental Authority of the jurisdiction of its formation as of a date not more than 30 days prior to the Closing Date;

     (R) a certificate of the secretary of Tercero Navarro dated the Closing Date: (1) setting forth the resolutions of the board of directors of Tercero Navarro authorizing the execution and delivery by Tercero Navarro and each Seller of this Agreement, the Transaction Documents and the consummation by those Parties of the Contemplated Transactions, and certifying that such resolutions were duly adopted and have not been rescinded or amended as of the Closing Date; and (2) attesting as to the incumbency and signature of each manager or officer of Tercero Navarro who will execute this Agreement or any Transaction Documents;

     (S) evidence reasonably satisfactory to Buyer of the release and discharge of all Liens and encumbrances securing any Indebtedness with respect to the Assets, including payoff letters and UCC-3 Termination Statements (or partial release/amendments, as applicable) with respect to all security interests filed against or encumbering any Asset, duly executed instruments of release, partial release, or reconveyance, as applicable, with respect to each of the real estate mortgages/deeds of trust securing any Indebtedness over any Asset, each delivered and filed in the appropriate public offices, and each other instrument, notice, release, or certificate necessary to effectuate the termination and release of the any Liens or security interests encumbering any of the Assets;

     (T) an executed counterpart of the Non-Circumvention Agreement between EGL and Buyer; and

     (U) an executed Parent Guaranty from LEG.

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     (ii) Buyer shall deliver the following to Sellers:

     (A) the Estimated Purchase Price, payable in cash and Enterprise Units as described in §2(d) of the Disclosure Schedule;

     (B) an executed counterpart from ESTG of the Bill of Sale;

     (C) an executed counterpart from ESTG of the Special Warranty Deed;

     (D) an executed counterpart from ESTG of the Gathering Lines Assignment;

     (E) an executed counterpart from ETPL of the Canales 12” Gathering Line Assignment;

     (F) an executed counterpart from ESTG of the Gathering System Permits Assignment;

     (G) an executed counterpart from ESTG of the Gathering System Contracts Assignment;

     (H) an executed counterpart from ESTG of the Easements Assignment;

     (I) a certificate of good standing, existence, or similar document with respect to Buyer issued by the appropriate Governmental Authority of the jurisdiction of its formation as of a date not more than 30 days prior to the Closing Date;

     (J) a certificate of the assistant secretary of Enterprise Products GP, LLC dated the Closing Date: (1) setting forth the resolutions of the board of directors of the Enterprise Products GP, LLC authorizing the execution and delivery by Buyer of this Agreement and the Transaction Documents and the consummation by Buyer of the Contemplated Transactions, and certifying that such resolutions were duly adopted and have not been rescinded or amended as of the Closing Date; and (2) attesting as to the incumbency and signature of each director or officer of Enterprise Products GP, LLC who will execute this Agreement or any Transaction Documents;

     (K) an executed counterpart from EH of the Shallow Rich Gathering Agreement;

     (L) an executed counterpart from EH of the Shallow Rich Processing Agreement;

     (M) an executed counterpart from EH of the Deep Rich Gathering Agreement;

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     (N) an executed counterpart from EH of the Deep Rich Processing Agreement;

     (O) an executed counterpart from EH of the Lean Gas Gathering Agreement;

     (P) an executed counterpart from EH of the Mexico Gathering Agreement;

     (Q) an executed counterpart from EH of the Mexico Processing Agreement;

     (R) an executed counterpart from ETPL of the Enterprise Texas Pipeline PSA/Lease Termination Letter; and

     (S) an executed counterpart from Buyer of the Non-Circumvention Agreement.

     (l) Material Consents.

     (i) If any Material Consents have not yet been obtained (or otherwise are not in full force and effect) as of Closing, in the case of each Material GS Contract as to which such Material Consents were not obtained (or otherwise are not in full force and effect) (the “Restricted Material GS Contracts”), Buyer shall either:

     (A) continue the effort to obtain the Consents; or

     (B) elect to have Sellers retain that Restricted Material GS Contract and all Liabilities arising therefrom or relating thereto.

     If Buyer elects to continue efforts to obtain any Material Consents, neither this Agreement nor any Transaction Documents will constitute a sale, assignment, assumption, transfer, conveyance or delivery or an attempted sale, assignment, assumption, transfer, conveyance or delivery of any Restricted Material GS Contract, and following Closing, Buyer shall use Best Efforts to obtain the Material Consents as quickly as practicable. Seller agrees to cooperate with Buyer in obtaining the Material Consents. Until a Material Consent for any Restricted Material GS Contract is obtained, the Parties shall cooperate with each other in any reasonable and lawful arrangements designed to provide to Buyer the benefits of use of the Restricted Material GS Contract for its term (or any right or benefit arising thereunder, including the enforcement for the benefit of Buyer of any and all rights of any Seller against a Third Person under that Restricted Material GS Contract). No Seller will take any action or suffer any omission which would limit or restrict or terminate in any material respect the benefits to Buyer of any Restricted Material GS Contract unless, in good faith and after consultation with and prior written Notice to Buyer, that Seller is ordered orally or in writing to do so by a Governmental Authority of competent jurisdiction or that Seller is otherwise required to do so by Law; provided that if any such order is appealable, that Seller will, at Buyer’s cost and expense, take any actions that Buyer requests to file and pursue that appeal and

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to obtain a stay of that order. Once a Material Consent for the sale, assignment, assumption, transfer, conveyance and delivery of a Restricted Material GS Contract is obtained, Sellers shall promptly assign, transfer, convey and deliver that Restricted Material GS Contract to Buyer, and Buyer shall assume the Liabilities under that Restricted Material GS Contract assigned to Buyer from and after the date of assignment to Buyer by execution and delivery of an instrument of conveyance reasonably satisfactory to Buyer within three Business Days following receipt of that Material Consent.

     (ii) If there are any Consents necessary for the assignment and transfer to Buyer of any contractual Assets not listed on §1(e) of the Disclosure Schedule (the “Non-Material Consents”) which have not yet been obtained (or otherwise are not in full force and effect) as of Closing, Buyer shall elect at Closing, in the case of each of the contracts as to which such Non-Material Consents were not obtained (or otherwise are not in full force and effect) (the “Restricted Non-Material GS Contracts”), whether to:

     (A) accept the assignment of such Restricted Non-Material GS Contract, in which case, as between Buyer and Sellers, such Restricted Non-Material GS Contract shall, to the maximum extent practicable and notwithstanding the failure to obtain the applicable Non-Material Consent, be transferred at Closing pursuant to the applicable Assignment of Contracts as elsewhere provided under this Agreement; or

     (B) reject the assignment of such Restricted Non-Material GS Contract, in which case: (1) neither this Agreement nor the applicable Gathering System Contracts Assignment nor any other Transaction Document will constitute a sale, assignment, assumption, conveyance or delivery or an attempted sale, assignment, assumption, transfer, conveyance or delivery of such Restricted Non-Material GS Contract; and (2) Sellers shall retain such Restricted Non-Material GS Contract and all Liabilities arising therefrom or relating thereto.

§3. Representations and Warranties of Buyer

     Buyer represents and warrants to Sellers that the statements contained in this §3 are correct and complete as of the Closing Date.

     (a) Organization. Buyer is a limited partnership duly organized, validly existing, and in good standing under the Laws of the State of Delaware, and Enterprise Products GP, LLC is a limited liability company duly organized, validly existing, and in good standing under the Laws of the State of Delaware.

     (b) Authorization of Transaction. Buyer has requisite power and authority to execute and deliver this Agreement, and Enterprise Products GP, LLC has all requisite authority on behalf of Buyer to grant all of the partnership actions described in this §3(b) and to perform its obligations under this Agreement and the applicable Transaction Documents. This Agreement and the applicable Transaction Documents have been duly executed by Buyer and constitute the valid and legally binding obligation of Buyer, enforceable in accordance with its terms and

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conditions, subject to General Exceptions to Enforceability. Except for filings required under the HSR Act, Buyer need not give any Notice to, make any filing with, or obtain any Consent of any Governmental Authority in order to consummate the Contemplated Transactions or to affect the legality, validity, binding effect, or enforceability of this Agreement or any applicable Transaction Document. The execution, delivery, and performance of all of the Contemplated Transactions have been duly authorized by Buyer.

     (c) Non-contravention. Neither the execution and delivery of this Agreement, nor the consummation of the Contemplated Transactions, will: (1) violate any Law or other restriction of any Governmental Authority to which Buyer is subject or any provision of its Governing Documents; or (2) result in a Breach of, constitute a default (or an event which with the giving of notice or lapse of time, or both, would become a default) under, result in the acceleration of, create in any Third Person the right to accelerate, terminate, modify, or cancel, or require any notice or Consent under any Contract, license or other arrangement to which Buyer is a party or by which it is bound or to which any of its assets is subject, except where the violation, conflict, Breach, default, acceleration, termination, modification, cancellation, failure to give notice, or Lien would not, or would not reasonably be expected to, individually or in the aggregate, be materially adverse to Buyer.

     (d) Brokers’ Fees. Buyer has no Liability to pay any fees or commissions to any broker, finder, or agent with respect to the Contemplated Transactions for which Sellers could become liable or obligated.

     (e) Available Funds and Enterprise Units. Buyer has sufficient cash resources and Enterprise Units to enable it to make payment in immediately available funds of the cash component of the Estimated Purchase Price and the issuance of Enterprise Units, at Closing as a result of the Contemplated Transactions.

     (f) Qualified for Gathering System Permits. To the Knowledge of Buyer, it is qualified to obtain, maintain, and control as of the Closing each material Gathering System Permit.

     (g) Independent Investigation. Buyer is knowledgeable in the business of: (1) owning and operating natural gas gathering, processing, and treatment facilities; (2) handling, storage, and delivery of natural gas, natural gas liquids, and condensate through pipeline systems; and (3) marketing of natural gas, natural gas liquids and condensate and has had access to the Assets, Sellers’ Representatives, and Sellers’ Records. In making the decision to enter into the Contemplated Transactions, Buyer has relied solely on its own independent due diligence investigations regarding the Assets, the representations and warranties of Sellers made in this Agreement and the Transaction Documents, and the covenants and undertakings of Sellers and LEG in this Agreement and the Transaction Documents. BUYER ACKNOWLEDGES THAT, EXCEPT AS EXPRESSLY SET OUT IN THIS AGREEMENT OR ANY TRANSACTION DOCUMENT, SELLERS HAVE NOT MADE ANY REPRESENTATION OR WARRANTY OF ANY KIND OR NATURE, EXPRESS, IMPLIED OR STATUTORY, INCLUDING, WARRANTIES OF THE CONDITION, USEFULNESS OR ADEQUACY OF THE ASSETS, QUALITY, MERCHANTABILITY, AND/OR FITNESS FOR A PARTICULAR PURPOSE, MARKETABILITY, AND CONFORMITY TO SAMPLES,

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AND BUYER IS ACQUIRING THE GATHERING SYSTEM AND THE ASSETS ON AN “AS IS, WHERE IS” BASIS.

§4. Representations and Warranties of Sellers

     Sellers represent and warrant to Buyer that the statements contained in this §4 are correct and complete, except as set forth in the Disclosure Schedule attached to this Agreement (the “Disclosure Schedule”).

     (a) Organization, Qualification, and Power. Each Seller is a limited partnership duly organized, validly existing and in good standing under the Laws of the State of Texas. Each Seller is duly authorized to own, lease and operate the Assets and the Gathering System and conduct business, and is qualified under the Laws of each jurisdiction where such qualification is required, except where the lack of such qualification would not, or would not reasonably be expected to, individually or in the aggregate, have a Material Adverse Effect. Each Seller has the requisite limited partnership power and authority to carry on its business and to own and use the Assets owned and used by it.

     (b) Authorization of Transaction. Each Seller has requisite power and authority, including authority granted to each by Tercero Navarro, the general partner of each Seller, to execute and deliver this Agreement and the applicable Transaction Documents and to perform its obligations under this Agreement, and Tercero Navarro has all requisite authority on behalf of each Seller to grant all of the partnership actions described in this §4(b). This Agreement and the applicable Transaction Documents have been duly executed by the Sellers and constitute the valid and legally binding obligations of Sellers, enforceable in accordance with its terms and conditions, subject to General Exceptions to Enforceability. The execution, delivery, and performance of all of the Contemplated Transactions have been duly authorized by Sellers.

     (c) Non-contravention. Neither the execution and delivery of this Agreement or any applicable Transaction Document, will: (1) violate any Law or other restriction of any Governmental Authority to which any Sellers are subject or any provision of the Governing Documents of Cerrito, CGM and EGL; or (2) conflict with, result in a Breach of, constitute a default (or an event which with the giving of notice or lapse of time, or both, would become a default) under, result in the acceleration of, create in any Third Person the right to accelerate, terminate, modify, or cancel, or require any notice or Consent under any Contract, license, instrument, or other arrangement to which Cerrito, CGM or EGL is a party or by which it is bound or to which any of the Assets is subject (or result in the imposition of any Lien upon any of the Assets), except where the violation, conflict, Breach, default, acceleration, termination, modification, cancellation, failure to give notice, or Lien would not, or would not reasonably be expected to, individually or in the aggregate be material to Sellers taken as a whole or to the Gathering Systems or the Assets. Except as set forth in §4(c) of the Disclosure Schedule with respect to HSR Act filings, Sellers do not need to give any notice to, make any filing with, or obtain any Consent of any Governmental Authority in order for the Parties to consummate the Contemplated Transactions.

     (d) Brokers’ Fees. Neither Sellers nor LEG has entered into any Contract or arrangement that would result in any Liability to pay any fees or commissions to any broker,

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finder, or agent with respect to the Contemplated Transactions for which Buyer or any of its Affiliates could become liable or obligated.

     (e) Assets.

     (i) Except as set forth on §4(e)(i) of the Disclosure Schedule, Cerrito, CGM or EGL, as applicable: (1) owns or leases all Assets necessary for the operation of the Gathering System as presently conducted, free and clear of all Liens (except for Permitted Encumbrances); and (2) has valid and indefeasible title to all owned Assets, and has valid leasehold interests in all leased Assets, free and clear of all Liens (except for Permitted Encumbrances).

     (ii) Neither Cerrito nor EGL has received written notice of any claims or disputes which challenge the rights of Cerrito or EGL to use, or allege a Breach or default under any Contracts granting to Cerrito or EGL rights to pipeline easements, right-of-way, licenses, and land use Permits, which claims or disputes, Breaches, or defaults would, or would be reasonably likely to, individually or in the aggregate, have a Material Adverse Effect. §4(e)(ii) of the Disclosure Schedule set forth all Assets which are subject to Consent to assign. Sellers are currently operating the Assets in material compliance with applicable Laws.

     (iii) The Assets constitute all of the assets and properties which are necessary for the current operation of the Gathering System.

     (f) Subsequent Events. Except as set forth on §4(f) of the Disclosure Schedule, since December 31, 2005: (1) there has not been any Material Adverse Change; and (2) the Gathering System has been operated only in the Ordinary Course of Business. Without limiting the generality of the foregoing, since that date no Seller has:

     (i) sold, leased, transferred, or assigned any of the Assets, tangible or intangible, other than for a fair consideration in the Ordinary Course of Business;

     (ii) entered into any Gathering System Contract or license (or series of related Contracts and licenses) either involving more than Five Hundred Thousand Dollars ($500,000) or outside the Ordinary Course of Business;

     (iii) accelerated, terminated, modified, or cancelled any Gathering System Contract or license (or series of related Contracts and licenses) (x) involving more than Five Hundred Thousand Dollars ($500,000) to which it is a party or by which it is bound, or (y) which is necessary to the operation of the Gathering System;

     (iv) imposed any Lien upon any of the Assets, tangible or intangible;

     (v) made any capital expenditure with respect to the Assets (or series of related capital expenditures) outside the Ordinary Course of Business;

     (vi) experienced any material damage, destruction, or loss (whether or not covered by insurance) to any of the Assets;

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     (vii) made or changed any election relating to Taxes related to the Assets, settled any claim or assessment relating to Taxes, or consented to any claim or assessment relating to Taxes or any waiver of the statute of limitations for any such claim or assessment;

     (viii) terminated, had terminated, or materially altered any Gathering System Contracts between such Seller and any of its principal customers or suppliers as listed in §4(f)(viii) of the Disclosure Schedule;

     (ix) entered into any settlement of any pending or threatened Proceeding relating to the Assets other than solely for cash; or

     (x) committed to do any of the foregoing.

     (g) Legal Compliance. Each Seller has complied with all applicable Laws related to the Assets and the Gathering System, the operation of the Assets and the Gathering System, and the Affected Employees, except where the failure to comply would not, or would not reasonably be expected to, individually or in the aggregate, have a Material Adverse Effect. Sellers have not received any written communication from any Governmental Authority or any other Person that alleges that the Gathering System or the Assets may not be in compliance, or may be subject to Liability, under any Law. Except as set forth in §4(g) of the Disclosure Schedule there are no investigations, Proceedings, or reviews pending or, to the Knowledge of each Seller, threatened by any Governmental Authority or other Person relating to any alleged violation of Law arising out of or related to the operation of the Gathering System.

     (h) Real Property. §4(h) of the Disclosure Schedule sets forth the address and description of each parcel of Owned Real Property. With respect to each such parcel of Owned Real Property, and except for matters that would not, or would not reasonably be expected to, individually or in the aggregate, have a Material Adverse Effect and except as noted in §4(h)(i) of the Disclosure Schedule:

     (i) Sellers have valid and indefeasible title, free and clear of all Liens (except Permitted Encumbrances);

     (ii) Sellers have not leased or otherwise granted to any Third Person the right to use or occupy such Owned Real Property or any portion thereof and there are no other Third Persons (other than Sellers) in possession of Owned Real Property;

     (iii) no Owned Real Property is in violation of any applicable Laws;

     (iv) there are no pending or, to the Knowledge of each Seller, threatened Proceedings to which any Seller is a party before any Governmental Authority with respect to the Owned Real Property, including any condemnation, expropriation or other similar Proceeding commenced by any Governmental Authority having the power to eminent domain against the Owned Real Property or any improvement therein. There is no pending application, Proceeding or other action before any Governmental Authority to which any Seller is a party or of which any Seller has received written notice with respect to zoning, licenses, Permits or other matters affecting the Owned Real Property;

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     (v) there has been no unrestored fire or other casualty damage which has affected any of the Owned Real Property;

     (vi) there are no outstanding options, rights of first offer, or rights of first refusal to purchase any Owned Real Property or any portion thereof or interest therein; and

     (vii) rights of ingress and egress to and from the Owned Real Property are adequate for the intended uses of the Owned Real Property.

     (i) Material GS Contracts. §4(i) of the Disclosure Schedule lists the following Gathering Systems Contracts (the “Material GS Contracts”):

     (i) all gas purchase Contracts, transportation Contracts, hedging Contracts, swap Contracts, Liabilities in respect of letters of credit, guarantees, joint venture Contracts, and other instruments, or otherwise relating to the Assets; and

     (ii) all other instruments relating to the Assets and the purchase, transportation by pipeline, gas processing, marketing, sale and supply of natural gas and other hydrocarbons.

     (iii) any Contract (or group of related Contracts) for the lease of personal property to or from any Person providing for lease payments in excess of One Hundred Thousand Dollars ($100,000) per annum;

     (iv) any Contract concerning a partnership or joint venture;

     (v) any Contract (or group of related Gathering System Contracts) under which it has created, incurred, assumed, or guaranteed any indebtedness for borrowed money, or any capitalized lease obligation;

     (vi) any Contract concerning confidentiality or noncompetition;

     (vii) any Contract under which the consequences of a default or termination could have a Material Adverse Effect;

     (viii) any Easement; and

     (ix) any other Contracts (or group of related Contracts) not enumerated in this §4(h), the performance of which involves consideration in excess of Two Hundred and Fifty Thousand Dollars ($250,000).

Sellers have made available to Buyer a correct and complete copy of each written Material GS Contract and Material Lease. With respect to each such Contract: (1) the Contract is legal, valid, binding, enforceable, and in full force and effect; (2) except as otherwise indicated in the Disclosure Schedule, the Contract will continue to be legal, valid, binding, enforceable, and in full force and effect on identical terms following the consummation of the Contemplated Transactions, and the assignment to Buyer or to any Buyer Designee will not violate any Laws;

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(3) Cerrito, CGM or EGL, as applicable, is not in Breach or default, and no event has occurred which with notice or lapse of time would constitute a Breach or default by Sellers, or permit termination, modification, or acceleration, under the Contract; and (4) to the Knowledge of each Seller, no other party is in Breach or default, and no event has occurred which with notice or lapse of time would constitute a Breach or default by such other party, or permit termination, modification or acceleration under the Contract other than in accordance with its terms nor has any other party repudiated any provision of the Contract. Upon assignment to Buyer or its designee of the HPLC Gas Purchase Agreement, Buyer or its designee shall have sole and exclusive claim to the Bonus Payment, as provided for in the HPLC Gas Purchase Agreement, including for all gas purchased pursuant to that certain Gas Purchase Agreement between HPLC and LPP dated effective August 1, 2005, as amended by the First Amendment to Gas Purchase Agreement dated October 1, 2005.

     (j) Litigation. There is no injunction, restraining order or Proceeding pending against any Seller that restrains or prohibits the consummation of the Contemplated Transactions. Except for the Proceedings identified on §4(j) of the Disclosure Schedule, there are no Proceedings pending, or to the Knowledge of any Seller threatened, against or affecting the Assets, the Gathering System or Sellers’ ownership or operation of the Assets or the Gathering System, the Affected Employees before or by any Governmental Authority or any Person. Notwithstanding anything in this Agreement to the contrary, the provisions of this §4(j) shall not relate to or cover Proceedings related to Environmental Laws with respect to the Assets which are covered exclusively by §4(m).

     (k) Labor and Employment.

     (i) None of the Sellers is a state or federal governmental contractor.

     (ii) None of the Sellers is a party to or bound by any collective bargaining agreement or any other Contract with any labor union or organization, and no Contract is being negotiated. Since January 1, 2004, none of the Sellers have experienced any strikes, work stoppages, slow downs, picketing or any other interference with work or production, grievances, claims of unfair labor practices, or other collective bargaining disputes or concerted action by their employees.

     (l) Gathering System Permits. Except as set forth in §4(l) of the Disclosure Schedule:

     (i) all Gathering System Permits have been obtained and are in full force and effect;

     (ii) no Seller has received written notification concerning violations that are currently in existence with respect to any Gathering System Permit; and

     (iii) no Proceeding is pending or, to the Knowledge of any Seller, has been threatened with respect to the revocation or limitation of any Gathering System Permit.

Notwithstanding anything in this Agreement to the contrary, the provisions of this §4(l) shall not relate to or cover any Permit or matter relating to or arising out of any Environmental Laws

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relating to the Assets and/or the Gathering System.

     (m) Environmental Matters.

     (i) Except as set forth in §4(m) of the Disclosure Schedule, to the Knowledge of Sellers, no Seller has caused or allowed the generation, use, treatment, transportation, recycling, reclamation, handling, manufacture, storage, or disposal of, or exposure of any Person or property to, any Hazardous Materials at, on or from the Assets, except in material compliance with all applicable Environmental Laws.

     (ii) To the Knowledge of any Seller, there has been no Release of any Hazardous Materials at, on, from, or underlying any of the Assets and the Gathering System in violation of applicable Environmental Laws or in any concentration or location that requires investigation or remediation or other corrective action under Environmental Laws or could otherwise result in a material Liability under applicable Environmental Laws.

     (iii) Sellers have secured all material Permits required under Environmental Laws for the ownership, use, and operation of the Gathering System and Assets, such Permits are in full force and effect and are not subject to any challenge, revocation action, or modification Proceeding by any Person, and Sellers are in material compliance with such Permits.

     (iv) Sellers have received no written inquiry or notice of any actual or threatened claim, Liability, or investigation related to or arising under any Environmental Law relating to the Assets or the Gathering System.

     (v) Sellers are not operating the Gathering System or any of the Assets under any waiver, compliance order, decree, or Contract, any consent decree or order, or corrective action decree or order issued by or entered into with any Governmental Authority under any Environmental Law or any Law regarding health or safety in the workplace.

     (vi) Sellers, the Assets, and the Gathering System operations are and, within the term of all applicable statutes of limitations, have been in compliance with Environmental Laws with respect to any matter that is not referred to in clauses (ii) through (v), and (vii) through (x) of this §4(m), except where the lack of such compliance would not, or would not reasonably be expected to, individually or in the aggregate, have a Material Adverse Effect.

     (vii) (1) No Seller has been named or, to the Knowledge of any Seller, threatened to be named as a potentially responsible party under CERCLA or any similar state Law relating to the Assets; (2) none of the Assets has been listed on the “National Priorities” list under CERCLA or any comparable listing or otherwise has been designated as a facility that is subject to an existing or, to the Knowledge of any Seller, threatened claim under CERCLA or any similar state Law; and (3) none of the Assets is subject to any Lien arising under Environmental Laws.

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     (viii) To the Knowledge of any Seller, none of the off-site locations where Hazardous Materials from any of the Assets have been stored, treated, recycled, disposed of, or Released is subject to any investigation or remedial obligation or other corrective action requirement under Environmental Laws.

     (ix) Sellers have provided Buyer with copies of all material environmental studies, audits, and assessments prepared by or in the possession of Sellers with respect to any of the Assets.

     (x) This §4(m) contains the sole and exclusive representations and warranties of Sellers with respect to any environmental matters, including any arising under any Environmental Laws.

     (n) Insurance. §4(n) of the Disclosure Schedule sets forth: (1) all insurance policies of Sellers (including the amounts and types of coverage) in connection with or with respect to the Assets and/or the Gathering System; (2) each material claim under any insurance policy made by or on behalf of each Seller with respect to the Assets and/or the Gathering System during the past three years, which claim was denied by the insurer; and (3) each application for insurance coverage made by or on behalf of each Seller with respect to the Assets and/or the Gathering System during the last three years that was rejected by the proposed insurer. All such insurance policies are in full force and effect and all premiums due and payable on such policies have been paid. No notice of cancellation of or indication of an intention not to renew any such insurance policy has been received by Sellers other than in the Ordinary Course of Business. Each Seller represents that all claims, or events that could reasonably be expected to give rise to a claim, have been reported to existing insurance carriers in accordance with policy requirements.

     (o) Governmental Regulation. No Seller is subject to regulation under the Public Utility Holding Company Act of 1935, the Federal Power Act, the Interstate Commerce Act, the Natural Gas Act, the Investment Company Act of 1940 or any state public utilities Laws.

     (p) Disclosure and Due Diligence. To the Knowledge of Sellers:

     (i) all materials disclosed to Buyer by Sellers and Sellers’ responses provided to Buyer’s due diligence information and data requests are true, accurate and complete and are the result of a thorough review and investigation by Sellers; and

     (ii) prior to the execution of this Agreement, Sellers have delivered to Buyer true and complete copies of the contractual Assets, and all security Contracts and other instruments creating or imposing any security interest encumbrance or adverse claim on the Assets, and any other documents or instruments identified or referred to in the Disclosure Schedule. Such delivery will not alone constitute adequate disclosure of those facts required to be disclosed in any section of the Disclosure Schedule, and notice of their contents (other than by express reference on the Disclosure Schedule) will in no way limit Sellers’ other obligations or Buyer’s other rights under this Agreement.

     (q) Taxes. With respect to the Assets and the Gathering System: (1) each Seller has timely filed all material Tax Returns required to be filed on or before the Effective Date; (2) each Seller has timely paid all material Taxes that are due and payable (whether or not shown, or

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required to be shown, on such Tax Returns) on or before the Effective Date; (3) each Seller has withheld and timely paid all Taxes required to have been withheld and paid in connection with amounts paid or owing to any employee, independent contractor, creditor, stockholder or other Third Person; (4) all Tax Returns filed by each Seller were complete and correct in all material respects, and such Tax Returns correctly reflected the material facts regarding the income, business, assets, operations, activities, status and other matters of each Seller and any other information required to be shown thereon; (5) no such Tax Returns are currently the subject of an audit by a Governmental Authority; (6) there are no Liens for Taxes upon any of the Assets, other than Liens for Taxes not yet due and payable and for which there are adequate reserves; (7) Sellers have not received written notice from a taxing authority in a jurisdiction where such entity does not file Tax Returns that such entity is subject to Tax in that jurisdiction; and (8) Buyer is not assuming an obligation to make a payment to an employee that will not be deductible under Section 280G of the Code.

     (r) No Other Agreements to Sell Assets. Neither Seller, their Affiliates nor any of their respective officers, directors, shareholders or members have any commitment or legal obligation, absolute or contingent, to any Person other than Buyer to sell, assign, transfer or effect a sale of any of the Assets, to sell or effect a sale of any of the capital stock, membership interests or partnership interests, as the case may be, of any Seller or any of their Affiliates or to effect any merger, consolidation, liquidation, dissolution or other reorganization of any Seller or any of its Affiliates and no Seller, its Affiliates or any of their respective officers, directors, shareholders or members has engaged in any discussions with any Person regarding any of the foregoing.

     (s) Disclaimer of Other Representations and Warranties. EXCEPT AS SPECIFICALLY SET FORTH IN THIS AGREEMENT OR IN ANY TRANSACTION DOCUMENT, BUYER ACKNOWLEDGES AND AGREES THAT EACH SELLER (AND LEG) HAS NOT MADE, DOES NOT MAKE, AND EXPRESSLY DISCLAIMS ANY WARRANTIES, REPRESENTATIONS, COVENANTS, OR GUARANTEES, EITHER EXPRESS OR IMPLIED, WHETHER ARISING BY OPERATION OF LAW OR OTHERWISE, AS TO THE MERCHANTABILITY, HABITABILITY, QUANTITY, QUALITY, OR PHYSICAL CONDITION OF THE ASSETS OR THEIR SUITABILITY OR FITNESS FOR ANY PARTICULAR PURPOSE OR USE. BUYER AFFIRMS THAT: (1) IT HAS INVESTIGATED AND INSPECTED THE ASSETS AND IS FAMILIAR AND SATISFIED WITH THEIR PHYSICAL CONDITION; AND (2) HAS MADE ITS OWN DETERMINATION AS TO THE: (A) MERCHANTABILITY, HABITABILITY, QUANTITY, QUALITY AND PHYSICAL CONDITION OF THE ASSETS, AND (B) THE ASSETS’ SUITABILITY OR FITNESS FOR ANY PARTICULAR PURPOSE OR USE. BUYER HEREBY ACCEPTS THE ASSETS IN THEIR PRESENT PHYSICAL CONDITION ON AN “AS IS”, “WHERE IS” BASIS, AND “WITH ALL FAULTS AND DEFECTS”, REGARDLESS OF HOW SUCH FAULTS AND DEFECTS WERE CAUSED OR CREATED (BY ANY SELLER’S OR LEG’S NEGLIGENCE, ACTIONS, OMISSIONS, OR FAULT, OR OTHERWISE), AND ACKNOWLEDGES THAT: (I) WITHOUT THIS ACCEPTANCE, THIS SALE WOULD NOT BE MADE, AND (II) SELLERS AND LEG SHALL NOT BE UNDER ANY OBLIGATION WHATSOEVER TO UNDERTAKE ANY REPAIR, ALTERATION, REMEDIATION, OR OTHER WORK OF ANY KIND WITH RESPECT TO ANY OF THE ASSETS.

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     SUBJECT TO BUYER’S RIGHTS UNDER: (1) THE OTHER PROVISIONS IN THIS AGREEMENT; AND (2) THE APPLICABLE TRANSACTION DOCUMENTS, EACH SELLER AND LEG ARE HEREBY EXPRESSLY RELEASED BY BUYER AND ITS SUCCESSORS AND ASSIGNS FROM ANY AND ALL RESPONSIBILITY, LIABILITY, OBLIGATIONS, AND CLAIMS, KNOWN AND UNKNOWN, WHETHER BASED UPON NEGLIGENCE, STRICT LIABILITY OR OTHERWISE, ARISING UNDER APPLICABLE LAWS, INCLUDING ANY OBLIGATIONS TO TAKE THE ASSETS BACK OR REDUCE THE BASE PURCHASE PRICE, OR ANY ACTIONS FOR CONTRIBUTION OR INDEMNITY, THAT BUYER OR ITS SUCCESSORS OR ASSIGNS MAY HAVE AGAINST ANY SELLER OR LEG OR THAT MAY ARISE IN THE FUTURE, ARISING FROM THE PHYSICAL CONDITION OF THE ASSETS OR RESULTING FROM OPERATION OF THE ASSETS, REGARDLESS OF HOW CAUSED OR CREATED (BY ANY SELLER’S OR LEG’S NEGLIGENCE, ACTIONS, OMISSIONS, OR FAULT, PURSUANT TO ANY STATUTORY SCHEME OF STRICT LIABILITY, OR OTHERWISE. BUYER FURTHER ACKNOWLEDGES THAT THE PROVISIONS OF THIS SECTION HAVE BEEN FULLY EXPLAINED TO BUYER AND THAT IT FULLY UNDERSTANDS AND ACCEPTS THE SAME AS A CONDITION TO PROCEEDING WITH THIS TRANSACTION. BUYER ACKNOWLEDGES THAT EXCEPT AS OTHERWISE PROVIDED IN THIS AGREEMENT OR IN ANY OTHER TRANSACTION DOCUMENT, NONE OF ANY SELLER’S OR LEG’S EMPLOYEES, AGENTS, OR REPRESENTATIVES HAS MADE ANY STATEMENTS OR REPRESENTATIONS CONTRARY TO THE PROVISIONS OF THIS SECTION.

     EXCEPT AS SPECIFICALLY STATED HEREIN OR IN ANY TRANSACTION DOCUMENT, EACH OF THE SELLERS AND LEG MAKES NO WARRANTY OR REPRESENTATION, EXPRESS, IMPLIED, STATUTORY OR OTHERWISE, AS TO THE ACCURACY OR COMPLETENESS OF ANY TITLE OPINION, DATA, REPORTS, RECORDS, PROJECTIONS, INFORMATION, OR MATERIALS NOW, HERETOFORE, OR HEREAFTER FURNISHED OR MADE AVAILABLE TO BUYER IN CONNECTION WITH THE ASSETS, INCLUDING, WITHOUT LIMITATION, ANY DESCRIPTION OF THE ASSETS, THE PRICING ASSUMPTIONS, THE PHYSICAL CONDITION OF THE ASSETS, ANY OTHER MATTERS CONTAINED IN THE DATA, OR ANY OTHER MATERIALS FURNISHED OR MADE AVAILABLE TO BUYER BY ANY SELLER OR LEG, OR BY EACH SELLER’S OR LEG’S REPRESENTATIVES. IN ENTERING INTO AND PERFORMING THIS AGREEMENT, BUYER HAS RELIED, AND WILL RELY, IN ADDITION TO SELLER’S AND LEG’S REPRESENTATIONS AND WARRANTIES IN THIS AGREEMENT AND IN THE APPLICABLE TRANSACTION DOCUMENTS, ON BUYER’S INDEPENDENT INVESTIGATION OF, AND JUDGMENT WITH RESPECT TO, THE ASSETS AND THEIR VALUE.

     EXCEPT AS EXPRESSLY SET FORTH IN THIS AGREEMENT OR IN THE TRANSACTION DOCUMENTS, SELLERS MAKE NO REPRESENTATION OR WARRANTY, EXPRESS OR IMPLIED, AT LAW OR IN EQUITY, IN RESPECT OF ITSELF, OR ANY OF ITS ASSETS, LIABILITIES OR OPERATIONS, INCLUDING, WITH RESPECT TO THE CONDITION, USEFULNESS OR ADEQUACY OF THE ASSETS, QUALITY, MERCHANTABILITY AND/OR FITNESS FOR A PARTICULAR PURPOSE, MARKETABILITY, OR CONFORMITY TO SAMPLES.

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     (t) Sellers’ Private Placement Representations. With respect to the Enterprise Units that Cerrito is to receive under this Agreement, Cerrito represents and warrants, as follows:

     (i) it is an Accredited Investor;

     (ii) it has such knowledge and experience in financial and business matters that it is capable of evaluating the merits and risks of the Enterprise Units, and is able to bear the economic risk of such investment for an indefinite period of time. It has been furnished access to such information and documents as it has requested and has been afforded an opportunity to ask questions of and receive answers from Representatives of Buyer concerning the terms and conditions of the issuance of the Enterprise Units contemplated hereby;

     (iii) it is acquiring the Enterprise Units issued pursuant to this Agreement for its own account for investment and not with a view towards the resale, transfer, or distribution thereof, nor with any present intention of distributing such Enterprise Units;

     (iv) it is not acquiring the Enterprise Units as a result of any advertisement, article, notice or other communication regarding the Enterprise Units published in any newspaper, magazine or similar media or broadcast over television or radio or presented at any seminar or any other general solicitation or general advertisement; and

     (v) it understands the Enterprise Units have not been registered under the Securities Act, or any state securities Laws, and that the transferability of the Enterprise Units that it is to receive under this Agreement will be restricted under the Securities Act unless such shares are registered under the Securities Act or an exemption from such registration is available.

     (u) Relationships with Related Persons. Except as disclosed in §4(u) of the Disclosure Schedule, no Related Person of any Seller has, or since January 1, 2004 has had, any interest in any property (whether real, personal or mixed and whether tangible or intangible) used in or pertaining to the Gathering System. No Related Person of any Seller owns, or since January 1, 2004 has owned, of record or as a beneficial owner, an equity interest or any other financial or profit interest in any Person that has: (1) had business dealings or a material financial interest in any transaction with such Seller relating to the Gathering System other than business dealings or transactions disclosed in §4(u) of the Disclosure Schedule, each of which has been conducted in the Ordinary Course of Business with such Seller at substantially prevailing market prices and on substantially prevailing market terms; or (2) engaged in competition with the Gathering System (a “Competing Business”) in any market presently served by the Gathering System, except for ownership of less than 1% of the outstanding capital stock of any Competing Business that is publicly traded on any recognized exchange or in the over-the-counter market. Except as set forth in §4(u) of the Disclosure Schedule, no Related Person of any Seller is a party to any of the Gathering System Contracts or other contractual Assets, or has any claim or right against, any of the Assets.

     (v) Conveyance Documents. Sellers’ deliveries under §2(k)(i)(A) through §2(k)(i)(H) constitute all the documents and instruments necessary to vest in Buyer at Closing all

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of Sellers’ right, title and interest in, to and under the Assets, free and clear of all Liens (other than Permitted Encumbrances).

     (w) No Undisclosed Material Liabilities. To the Knowledge of the Sellers, there are no Liabilities attributable to or affecting the Gathering System or the Assets, and there is no existing condition, situation or set of circumstances that could reasonably be expected to result in such a Liability, other than Liabilities incurred in the Ordinary Course of Business (none of which results from, arises out of, relates to, is the nature of, or was caused by any Breach of Contract, Breach of warranty, tort, infringement or violation of Law), that are not (singly or in the aggregate) material to the Assets or the Gathering System.

     (x) Other Information. To the Knowledge of the Sellers, none of the documents or information delivered to Buyer by any Representative of any Seller or LEG in connection with the Contemplated Transactions contains any untrue statement of a material fact or omits to state a material fact necessary in order to make the statements contained therein not misleading. Neither the representations and warranties of any Seller or LEG, nor the indemnification obligations of any Seller or LEG, is affected, qualified, modified or deemed waived by reason of the fact that Buyer knew or should have known that any representation or warranty of any Seller or LEG is or might be inaccurate in any respect.

     (y) Indebtedness. §1(b) of the Disclosure Schedule lists all Indebtedness.

§5. Labor and Employment; Employee Benefits

     (a) Affected Employees. To the extent permitted by applicable Laws, Sellers have provided to Buyer and its Affiliates a list of the Affected Employees, including each Affected Employee’s name, job title, and work location, and the additional information regarding each Affected Employee listed on §5(a) of the Disclosure Schedule.

     (b) Employment of Affected Employees by Buyer.

     (i) Neither Buyer nor its Affiliates are obligated to hire any Affected Employee but will have interviewed all Affected Employees it chooses to interview, including the employees listed in §5(b)(i) of the Disclosure Schedule (the “Identified Employees”) within ten days after the Closing Date. Seller has granted prior to Closing and shall after Closing grant to Buyer, to the extent permitted by applicable Laws, reasonable access to Sellers’ field offices and personnel records of Sellers for the purpose of preparing for and conducting employment interviews with all Identified Employees.

     (ii) Buyer and its Affiliates will determine which of the Identified Employees will be offered employment by Buyer’s Affiliate and hired by Buyer’s Affiliate after their acceptance of such employment offers and their passing Buyer’s Affiliate’s standard pre-employment screening procedures (“Transferred Employees”). Buyer’s Affiliate will have the right to offer employment to any or all Identified Employees. Buyer’s Affiliate will extend all offers of employment, if any, to Identified Employees no later than ten days after the Closing Date. Sellers will not, directly or indirectly, interfere with any of Buyer’s Affiliate’s offers of employment to Identified Employees, make a competing offer of employment to any Identified Employees, or recommend or suggest that any

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Identified Employees decline Buyer’s Affiliate’s offer of employment. Sellers, in their sole discretion, may retain any Identified Employees who are not offered employment by Buyer’s Affiliate or who, without any interference by Sellers, decline Buyer’s Affiliate’s offer of employment. Buyer and Buyer’s Affiliates will have no responsibility or liability with respect to any Affected Employees except the Transferred Employees, and then only after the Transfer Date.

     (iii) Buyer’s Affiliate’s offers of employment to any Identified Employees shall be for employment to begin on the first day of the second month immediately following the Closing Date (the “Transfer Date”). Sellers shall retain and employ all Affected Employees to whom Buyer’s Affiliate has given an offer of employment until the Transfer Date. Sellers shall terminate the employment of all Transferred Employees effective as of 12:01 a.m. Central time on the Transfer Date. Buyer agrees to reimburse Sellers for Sellers’ cost of both the compensation and benefits Sellers paid or provided to all Transferred Employees between the Closing Date and the Transfer Date as provided in §6(d). Sellers shall reasonably cooperate with Buyer’s Affiliate in Buyer’s Affiliate’s efforts to offer employment to, and conduct pre-employment background checks and other screening procedures of, Identified Employees so that all such pre-employment screenings may be completed by the Transfer Date.

     (iv) Neither Sellers nor their Related Persons shall solicit the employment of any Transferred Employee for a period of at least 12 months after the Transfer Date.

     (v) It is understood and agreed that: (1) Buyer’s Affiliate’s expressed intention to extend offers of employment as set forth in this section does not constitute any commitment, Contract or understanding (expressed or implied) of any obligation on the part of Buyer or Buyer’s Affiliates to an employment relationship of any fixed term or duration or upon any terms or conditions other than those that Buyer or Buyer’s Affiliates may establish pursuant to individual offers of employment to Affected Employees; and (2) employment offered by Buyer’s Affiliate is “at will” and may be terminated by Buyer’s Affiliate or by a Transferred Employee at any time for any reason (subject to any written commitments to the contrary made by Buyer, Buyer’s Affiliates, the Transferred Employee, and applicable Laws). Nothing in this Agreement shall be deemed to prevent or restrict in any way the right of Buyer’s Affiliate to terminate, reassign, promote, or demote any of the Transferred Employees after the Transfer Date or to change adversely or favorably the title, powers, duties, responsibilities, functions, locations, salaries, other compensation or terms or conditions of employment of such employees.

     (c) Salaries and Benefits.

     (i) Sellers shall, within its normal course of business, but not later than 15 days after the Transfer Date, pay all wages and other remuneration due to Transferred Employees with respect to their services as employees of Sellers through the close of business on the day before the Transfer Date, including pro rata bonus payments and all vacation pay earned and vested prior to the Transfer Date. In addition, Sellers shall pay any benefits due to Affected Employees under any Employee Plan (or required by law or contract), including any termination or severance payments due to the Affected

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Employees, in accordance with the terms of the applicable Employee Plan (or the applicable law or contract, as the case may be).

     (ii) Sellers shall be liable for, and indemnify Buyer and Buyer’s Affiliates for, any liability arising in connection with Seller’s obligation for payment hereunder of any salary or remuneration due to Affected Employees by Sellers and any claims under Employee Plans that were made or incurred by Affected Employees through the Transfer Date. For purposes of this §5, a claim will be deemed incurred, in the case of hospital, medical or dental benefits, when the services that are the subject of the claim are performed and, in the case of other benefits (such as disability or life insurance), when an event has occurred or when a condition has been diagnosed that entitles the employee to the benefit.

     (iii) Each Seller shall provide a copy of the most recent determination letter from the Internal Revenue Service for each Employee Plan that is intended to be qualified under Section 401(a) of the Code, and shall cause each Transferred Employee to become 100% vested in his or her accrued benefits under such plan that is intended to be qualified under Section 401(a) of the Code.

     (iv) §5(c)(iv) of the Disclosure Schedule contains a complete list of all Employee Plans covering the Affected Employees. Each Seller shall have sole Liability and responsibility for all matters arising out of any Affected Employee’s employment with that Seller, including, all accrued but untaken vacation/paid time off or carry-overs of vacation/paid time off from previous years and claims accruing under any Employee Plans, and Buyer and Buyer’s Affiliates shall have no Liability for the same or for any matters relating to that Seller’s employment of any Affected Employees, including offering continuation health coverage as described in Section 4980B of the Code to any eligible Affected Employee and his or her eligible dependents.

     (v) Each Seller shall furnish to Buyer a summary of the material terms of each Employee Plan of that Seller affecting the Transferred Employees, including the Seller’s vacation and paid-time-off policy and a copy of the summary plan description for each Employee Plan for which a summary plan description exists.

     (vi) Sellers shall not change any compensation or benefit levels for any Transferred Employee between the Closing Date and the Transfer Date, except for any regularly scheduled adjustment to compensation that has previously been disclosed in writing to Buyer prior to Closing.

     (d) Sellers’ Group Health Plans. As of the Closing Date, Sellers shall be solely responsible for providing COBRA continuation health coverage under Sellers’ group health plans: (1) with respect to each individual who is a “qualified beneficiary”, as such term is defined under COBRA, on and before the Transfer Date and each individual who becomes a “qualified beneficiary” in connection with the purchase described herein; and (2) who was (or, with respect to eligible dependents, whose qualifying event occurred in connection with) an Affected Employee whose last employment prior to the “qualifying event”, as such term is defined under COBRA, was associated with the purchased assets (the “Qualified Beneficiaries”),

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including providing the appropriate COBRA notices and making available any coverage required under COBRA with respect to such individuals. For the period of COBRA continuation coverage provided under the Sellers’ group health plan, Buyer will assist Sellers or Sellers’ group health plans with obtaining the last known address of such individuals as may be required to administer continuation coverage in accordance with COBRA and its regulations and to otherwise comply with applicable Laws. Any group health plan maintained by Buyer shall permit immediate participation by Transferred Employees as of the Transfer Date without any exclusions or limitations for preexisting conditions if permitted by the plan document or insurance contract governing Buyer’s group health plans. For the period of COBRA continuation coverage required to be provided under the Sellers’ group health plan, the Qualified Beneficiaries will remain responsible for payment of the amount of premiums that they would otherwise have been required to pay under the applicable group health plan if they were still employed by Sellers, plus any additional premium permitted under COBRA and imposed for the cost of continuation coverage for Qualified Beneficiaries under Sellers’ group health plans. Sellers shall not be obligated to pay or reimburse any health care claims incurred by Qualified Beneficiaries after the date on which COBRA continuation coverage ends.

     (e) Sellers’ Retirement and Savings Plans. All Transferred Employees who are participants in Sellers’ retirement plans shall retain their accrued benefits under the applicable Seller’s retirement plans as of the Transfer Date, and Sellers (or Sellers’ retirement plans) shall retain sole Liability for the payment of such benefits as and when such Transferred Employees become eligible therefor under the terms of such plans. Sellers shall cause the assets of each such Employee Plan attributable to the accrued benefits of Transferred Employees to equal or exceed the benefit Liabilities of such Employee Plan with respect to such Transferred Employees on a plan-termination basis as of the Transfer Date.

     (f) General Employee Provisions.

     (i) Sellers and Buyer or Buyer’s Affiliates shall give any notices required by applicable Laws and take whatever other actions with respect to the plans, programs and policies described in this §5 as may be necessary to carry out the arrangements described in this §5.

     (ii) Sellers shall provide Buyer and Buyer’s Affiliates with such plan documents, employee data or other information as may be reasonably required to carry out the arrangements described in this §5.

     (iii) Sellers shall provide Buyer’s Affiliate with completed I-9 forms of Sellers and attachments with respect to all Transferred Employees, except for such employees as the Seller Representative certifies in writing to Buyer’s Affiliate are exempt from such requirement.

     (iv) Sellers agree that Buyer and Buyer’s Affiliate shall not have any Liability, whether to Sellers, Affected Employees, former employees, their dependents, beneficiaries or to any other Person, with respect to any Employee Plan maintained by Sellers.

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     (v) Sellers shall copy and transfer to Buyer’s Affiliates all books, records and personnel files relating to the Transferred Employees, including copies of drug tests and background checks, no later than 15 Business Days before the Transfer Date. Sellers and Buyer shall cooperate to obtain a release of records satisfactory to Sellers from each Transferred Employee.

§6. Post-Closing Covenants

     The Parties agree as follows with respect to the period following Closing:

     (a) General. In case at any time after Closing any further action is necessary or desirable to carry out the purposes of this Agreement, each of the Parties will take such further action (including the execution and delivery of such further instruments and documents) as the other Party reasonably may request, all at the sole cost and expense of the requesting Party (unless the request is made pursuant to §2(f), or the requesting Party is entitled to indemnification under §7(a)).

     (b) Payment of Obligations Under Lehman Agreement. At Closing, Cerrito shall pay and discharge all amounts owed at Closing by Cerrito to Lehman Brothers, Inc. (“Lehman”) pursuant to that Letter Agreement, dated March 21, 2006 between Lehman and Cerrito.

     (c) Preferential Right to Purchase. From and after Closing, if Buyer desires to sell all or substantially all the Assets to any Person other than an Affiliate in a single transaction or a series of related transactions in which the Assets comprise more than 50% of the aggregate value of such transaction or transactions, then Buyer shall promptly give written notice to Sellers with full information concerning its proposed disposition, which shall include the name and address of the prospective transferee (who must be ready, willing, and able to purchase), the purchase price and all other terms of the offer. Sellers shall have an optional prior right, for a period of 60 days after notice is delivered, to purchase for the same consideration on the same terms and conditions the Asset or Assets Buyer proposes to sell.

     (d) Transition Services. In order to facilitate the full transition of operating activities and functions in the Assets following the Closing Date, for a period of 120 days commencing on the Closing Date, Sellers shall provide or cause to be provided to Buyer field operating and administrative support services of the same or substantially similar nature that Sellers or their Affiliates have provided with respect to the Gathering System (“Transition Services”). Sellers will continue to provide Transition Services following the last day of that 120-day period, on a month-to-month basis until Sellers provide written notice of their intent to terminate the Transition Services at the end of any month after the initial 120-day term, upon no less than 60 days prior written notice. Buyer may terminate any of the Transition Services at any time upon 30 days written notice to the Seller Representative. Sellers shall perform or cause to be performed the Transition Services in accordance with the Service Standard. Buyer, upon not less than ten days’ written Notice from Buyer to the Seller Representative, at any time and from time to time may, as of the date set forth in that notice (which may not precede the end of such ten-day period without Sellers’ approval), terminate any or all of the Transition Services. Buyer shall reimburse Sellers for the Direct Costs of the Transition Services provided in accordance with this §6(d) and with the Service Standard and billed as a Direct Cost. No later than the tenth

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Business Day of each calendar month, beginning with the calendar month immediately following Closing, Sellers will submit an invoice to Buyer for the Direct Costs incurred during the prior calendar month which invoice shall include reasonable supporting documentation such as the nature and amount of Direct Costs and the Transition Services to which they are attributable. If the Closing Date is on a day other than the last day of a month, the invoice shall be only for those Transition Services provided from such date until the end of the month in which Closing took place. Buyer shall pay the undisputed portion of each invoice within 30 days after its receipt. Records shall be maintained by Sellers for a period of two years after the final invoice for Transition Services is paid by Buyer. Upon reasonable prior notice of not less than five Business Days, Buyer and its Representatives shall have the right to audit and inspect, at Buyer’s expense, records applicable to the Transition Services and invoices during normal business hours at LEG’s offices for a period of two years following the date an invoice is delivered to Buyer. Except as specifically provided in this Agreement, Sellers will not be liable to Buyer for any Adverse Consequences arising from their provision of the Transition Services under this Agreement. Sellers shall indemnify Buyer and its Affiliates from and against any and all Adverse Consequences arising out of or relating to any gross negligence, fraud, willful misconduct, or bad faith in their performance of the Transition Services.

     (e) Post-Closing Settlement of Income and Expenses Received or Paid. After Closing: (1) Buyer shall remit to the appropriate Seller any revenues or income received by Buyer which are attributable to the Assets prior to the Effective Time, including accounts receivable attributable to the sale and transportation of natural gas and natural gas condensate during periods prior to the Effective Time; (2) Sellers shall remit to Buyer any revenues or income that are attributable to the Assets after the Effective Time, including proceeds from the sale and transportation of natural gas and natural gas condensate for periods following the Effective Time; (3) Buyer shall pay to any Seller, after receipt of such Seller’s invoice, any accounts payable and expenses paid by such Seller and incurred in the Ordinary Course of Business or in response to an emergency which are attributable to ownership and operation of the Assets after the Effective Time; and (4) the appropriate Seller shall pay to Buyer, after receipt of Buyer’s invoice, any accounts payable or expenses paid by Buyer which are attributable to the ownership and operation of the Assets before the Effective Time.

     (f) Shelf Registration Rights.

     (i) Shelf Registration Rights. Buyer shall, at its cost, prepare and file with the Securities and Exchange Commission (the “Commission”), as promptly as practicable (but in no event more than 30 days after Closing), a registration statement on Form S-3 (or such other appropriate form) that covers all of the Enterprise Units that Cerrito received as part of the Final Purchase Price (and any Enterprise Units received as a result of any split, dividend distribution or similar transaction) (the “Registrable Securities”) to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act (the “Shelf Registration Statement”). Buyer shall use its commercially reasonable efforts to have the Shelf Registration Statement declared effective within 180 days after Closing. After the Shelf Registration Statement is declared effective, Buyer shall use its commercially reasonable efforts to keep the Shelf Registration Statement continuously effective in order to permit the prospectus included therein to be lawfully delivered by Cerrito or its Lawful Assigns, (each such Person, if included in the Shelf Registration

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Statement shall be referred to herein as a “Registered Seller” and collectively the “Registered Sellers”) and shall prepare and file with the Commission such amendments and supplements to the Shelf Registration Statement and the prospectus contained therein and to take any other action as may be necessary to keep such Shelf Registration Statement effective until the earlier of: (1) the date that all of the Registrable Securities have been sold; or (2) the date on which the remaining Registrable Securities are eligible for resale pursuant to Rule 144 under the Securities Act without restriction. Each Registered Seller shall notify Buyer at such time as such Registered Seller has sold or otherwise disposed of all of its Registrable Securities. Buyer agrees to amend or supplement the Shelf Registration Statement and the prospectus included therein to include as a selling shareholder any Lawful Assigns that notifies Buyer that it has received Registrable Securities prior to the expiration of this §6(f). Notwithstanding any other provisions of this Agreement to the contrary, Buyer shall cause the Shelf Registration Statement and the prospectus and any amendment or supplement thereto, as of the effective date of the Shelf Registration Statement, amendment or supplement, (a) to comply in all material respects with the applicable requirements of the Securities Act and the rules and regulations of the Commission and (b) not to contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in light of the circumstances under which they were made, not misleading; provided, however, that each Registered Seller shall be solely responsible for information regarding such Registered Seller as furnished to Buyer in writing specifically for use in the Shelf Registration Statement or any supplement or amendment thereto.

     (ii) Blackout Period for Shelf Registration Statement. If Buyer: (1) is in possession of material nonpublic information that it deems advisable not to disclose; (2) is engaged in active negotiations or planning for a merger or acquisition or disposition transaction; (3) determines that Form S-3 is not available; (4) determines that an amendment or supplement to the Shelf Registration Statement is necessary; or (5) determines that it would not be in the best interests of Buyer for the Registrable Securities to be sold because such sale would materially interfere with Buyer’s business or financing plans, Buyer may deliver written notice to the Registered Sellers to the effect that such Registered Sellers may not make offers or sales under the Shelf Registration Statement for a period not to exceed 60 days from the date of each such notice; provided, however, that the aggregate number of days Buyer may suspend the use of the Shelf Registration Statement hereunder shall not exceed 120 days during any 12-month period.

     (iii) Shelf Registration Notice. Each Registered Seller shall deliver a written notice to Buyer (the “Shelf Registration Notice”) that it intends to make offers or sales under the Shelf Registration Statement prior to any such offer or sale. Such Shelf Registration Notice shall include the number of Enterprise Units to be sold by such Registered Seller, and such Registered Seller’s address, facsimile and e-mail address, written notice to which shall constitute notice to such Registered Seller for the purposes of this §6. If Buyer determines that it is necessary to amend or supplement the prospectus, Buyer shall prepare and file or cause such amendment or supplement to be prepared and filed with the Commission as soon as possible, and in no event later than ten Business Days after receipt of the Shelf Registration Notice. In the event that an

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amendment or supplement is necessary and Buyer elects to exercise its right to blackout such Registered Seller’s sales pursuant to §6(f)(ii) above, any such delay shall count for purposes of the sixty (60) day limit described in §6(f)(ii) above. The Registered Sellers may not offer or sell any Registrable Securities under the Shelf Registration Statement until it has received from Buyer (i) confirmation that no amendment or supplement is needed or (ii) copies of the prospectus, as amended or supplemented as the case may be, and has received written notice from Buyer that the Shelf Registration Statement and any post-effective amendments have become effective.

     (iv) Expenses. Buyer shall bear all expenses incurred in connection with the registration under this §6(f) (excluding underwriter’s and broker’s discounts and commissions and fees relating to the Registrable Securities and legal fees of counsel for Sellers), including, all federal and “blue sky” registration, filing and qualification fees, printer’s and accounting fees, and legal fees of counsel for Buyer.

     (v) Indemnification.

     (A) Buyer shall indemnify each Registered Seller and each Person controlling (as defined in Section 15 of the Securities Act) such Registered Seller and each of such controlling Person’s officers and directors, if any, and shall also indemnify each underwriter, if any, and each Person who controls any underwriter, against all claims, losses, damages and Liabilities (or actions in respect thereof) arising out of or based on any of the following statements, omissions or violations (each, a “Violation”):

     (1) any untrue statement (or alleged untrue statement) of a material fact contained in the Shelf Registration Statement, including any preliminary prospectus or final prospectus contained therein or any amendments or supplements thereto;

     (2) any omission (or alleged omission) to state therein a material fact required to be stated therein or necessary to make the statements therein not misleading; or

     (3) any violation by Buyer of any rule or regulation promulgated under the Securities Act applicable to Buyer and relating to action or inaction required of Buyer in connection with the registration.

Buyer shall reimburse each Registered Seller and each Person controlling such Registered Seller, and each of such controlling Person’s officers and directors, if any, each such underwriter, and each Person who controls such underwriter, for any legal and other expenses reasonably incurred in connection with investigating or defending any such claim, loss, damage, Liability or action; provided, however, that Buyer shall not be liable in any such case to the Registered Sellers or any controlling Person to the extent that any such claim, loss, damage, Liability or expense arises out of or is based upon a Violation which occurs in reliance upon written information that a Registered Seller furnished to Buyer, where such

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information is specifically provided for use in the Shelf Registration Statement, including any preliminary prospectus or final prospectus contained therein or in any amendment or supplement thereto.

     (B) Each Registered Seller shall severally indemnify Buyer, each underwriter, if any, of Buyer’s securities covered by the Shelf Registration Statement, each Person who controls (as defined in Section 15 of the Securities Act) Buyer or such underwriter, and each of such controlling Person’s officers and directors, if any, against all claims, losses, damages and Liabilities (or actions in respect thereof) arising out of or based on any Violation, and shall reimburse Buyer and any such directors and officers, underwriters and control Persons for any legal or any other expenses reasonably incurred in connection with investigating or defending any such claim, loss, damage, Liability or action, in each case to the extent, but only to the extent, that such Violation is made in the Shelf Registration Statement, including any preliminary prospectus or final prospectus contained therein or any amendment or supplement thereto, based upon and in conformity with written information that the applicable Registered Seller furnished to Buyer specifically for use therein; provided, however, that each Registered Seller’s obligations hereunder will be limited to an amount equal to the proceeds received by such Registered Seller in exchange for Registrable Securities sold pursuant to the prospectus which contained such untrue statement, omission or violation and shall relate solely to untrue statements, omissions and violations resulting from written information provided by such Registered Seller.

     (C) In connection with any indemnity pursuant to §6(f), each indemnified party shall give notice to the indemnifying party promptly after such indemnified party has knowledge of any claim as to which indemnity may be sought and shall permit the indemnifying party to assume the defense of any such claim or any litigation resulting therefrom, provided that counsel for the indemnifying party, who shall conduct the defense of such claim or any litigation resulting therefrom, shall be approved by the indemnified party (whose approval shall not be unreasonably withheld). Any such assumption of the defense and control of a claim will constitute an acknowledgement and acceptance by the indemnifying party of its obligation to indemnify the indemnified party claim under this §6(f). The indemnified party may participate in such defense with counsel of its own choosing, but the fees and expenses of such counsel shall be at such indemnified party’s expense unless: (1) the indemnifying party and the indemnified party shall have agreed to the retention of such counsel; or (2) the named parties to any such proceeding (including any impleaded parties) include both the indemnifying party and the indemnified party and representation of both parties by the same counsel would be inappropriate due to actual or potential conflicting interests between them. The failure of any indemnified party to give notice as provided herein shall relieve the indemnifying party of its obligations under this §6(f) only if such failure is prejudicial to the ability of the indemnifying party to defend such action, and such failure shall in no event relieve the indemnifying party of any liability that it may have to any indemnified party otherwise than under this §6(f). No indemnifying party, in the defense of any

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such claim or litigation, shall, except with the Consent of each indemnified party, Consent to entry of any judgment or enter into any settlement that does not include as an unconditional term thereof the giving by the claimant or plaintiff to such indemnified party of a release from all liability with respect to such claim or proceeding.

     (g) Lock-up of Enterprise Units. Cerrito may not offer, sell, contract to sell, pledge, or otherwise dispose of (or enter into any transaction which is designed to, or might reasonably be expected to, result in the disposition of (whether by actual disposition or effective economic disposition due to cash settlement or otherwise) by Sellers or any of their Affiliates), directly or indirectly, or establish or increase a put equivalent position or liquidate or decrease a call equivalent position within the meaning of Section 16 of the Securities Exchange Act of 1934 with respect to, any Registrable Securities, or publicly announce an intention to effect any such transaction, for a period of 90 days after the Closing Date (the “Lock-Up Period”); provided, however, that Cerrito may make any private transfer to a Lawful Assign during the Lock-up Period. After the expiration of the Lock-Up Period, Cerrito may not at any time sell in excess of 75,000 Registrable Securities in a single transaction, without Buyer’s prior written Consent, which Buyer will not unreasonably withhold. Cerrito shall give Buyer written notice of such proposed sale, transfer or assignment. Buyer shall have until 5:00 p.m. Central time on the second full Business Day after receipt of such notice to provide Cerrito with its written Consent or notice that it does not Consent to such sale or transfer. The failure of Buyer to respond in writing by 5:00 p.m. Central time on the second Business Day after receipt of notice shall be deemed to be Consent to such sale, transfer or assignment for purposes of this §6(g). Notwithstanding the above Lock-up Period, Cerrito shall have the right to sell, without the prior approval of Buyer, up to an aggregate of Fifteen Million Dollars ($15,000,000) of Registrable Securities after the expiration of the 30-day period immediately following the Closing Date (excluding any transfers to any Lawful Assigns, but including any subsequent resales by such Lawful Assigns); provided, however, that Cerrito may not exercise such right to sell during the 60 trading day period after the closing of an offering by Buyer of any Enterprise Units. Notwithstanding any other provision of this Agreement, any sale or transfer of Registrable Securities by Cerrito or any Lawful Assign (other than to Buyer) shall be made pursuant to the Shelf Registration Statement, once declared effective, or an exemption from registration under the Securities Act evidenced by an opinion of counsel confirming the availability of such exemption. A “Lawful Assign” means any Person: (1) to which Cerrito may transfer Registrable Securities in compliance with the registration requirements of the Securities Act or an exemption therefrom as evidenced by an opinion of counsel; and (2) such Person agrees in writing to be bound by the Lock-up provisions in §6(g) to the same extent as Cerrito and the provisions in this §6 applicable to Registered Sellers, but only in the event that (in the case of the Registered Sellers’ provisions) such Person will be a Registered Seller.

     (h) Financial Information. Within 90 days after Closing, Sellers will provide Buyer with the following financial information: (1) audited combined financial statements of the Assets consisting of balance sheets at December 31, 2005 and 2004 and income statements, cash flow statements and equity statements for each of the years ended December 31, 2005, 2004 and 2003; and (2) unaudited combined quarterly financial statements of the Assets consisting of balance sheets, income statements, cash flow statements and equity statements for each of the quarters ending March 31, 2005, June 30, 2005, September 30, 2005, December 31, 2005, March

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31, 2006 and June 30, 2006. In addition, Sellers will provide Buyer a written summary of significant changes in earnings of the Assets for the following periods (a) fiscal year 2005 versus fiscal year 2004, (b) fiscal year 2004 versus fiscal year 2003, and (c) quarter-on-quarter variance analysis beginning with the quarter ended March 31, 2005 and extending through the quarter ended June 30, 2006. The audited financial statements referred to herein shall include such footnotes, financial schedules and other information as to be fully compliant with Regulation S-X of the U.S. Securities and Exchange Commission. The independent auditor selected to prepare the audited financial statements shall be mutually agreed to by Sellers and Buyer and shall be qualified to perform such work.

     (i) Customer and Other Business Relationships. For a period of six months after Closing, LEG and Sellers will use their reasonable commercial efforts, without incurring any out-of-pocket costs, to continue and maintain for the benefit of Buyer those business relationships of Sellers existing prior to Closing and relating to the Gathering System, including relationships with lessors, employees, regulatory authorities, licensors, customers, suppliers and others, and Sellers will satisfy any Excluded Liabilities in a manner that is not detrimental to any of such relationships. Sellers shall refer to Buyer all inquiries relating to the Gathering System. No Seller nor any of its Related Persons will take any action that would tend to diminish the value of the Assets after Closing or that would interfere with the Gathering System after Closing, including disparaging the Buyer’s name or the Gathering System.

     (j) Certain Actions by Sellers. Promptly after Closing, Sellers shall undertake the actions described in §6(j) of the Disclosure Schedule. Upon Sellers’ full completion of the actions described in §6(j) of the Disclosure Schedule as determined by Buyer, Sellers will have no further Liability to Buyer with respect to those actions.

     (k) VOC Site Assessment. Within 120 days of Closing, Buyer shall complete an assessment of the VOC emissions of each site listed in §6(k) of the Disclosure Schedule, using accepted industry and environmental practices for purposes of quantifying potential emissions based on maximum design capacity of the facilities located on such sites. In the event Buyer determines that any site has the potential to emit 25 tons or more of VOCs per year, Buyer shall retain One Hundred Seventy Five Thousand Dollars ($175,000) of the VOC Holdback Amount for each such site and such amounts shall not be part of the Final Purchase Price. In the event Buyer determines that any site does not has the potential to emit 25 tons or more of VOCs per year, Buyer shall remit One Hundred Seventy Five Thousand Dollars ($175,000) of the VOC Holdback Amount to Sellers for each such site and such amounts shall become part of the Final Purchase Price.

     (l) Transfer of Interim Excluded Assets. Sellers shall transfer the Interim Excluded Assets, except for the radios described in §1(c) of the Disclosure Schedule, to ESTG or another Buyer Designee promptly after Buyer delivers written notice to the Seller Representative requesting such transfer. Buyer shall determine whether such radios are compatible with Buyer’s operation of the Gathering System. Sellers shall transfer to ESTG or another Buyer Designee up to 21 of such radios that Buyer determines are compatible with Buyer’s operation of the Gathering System.

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     (m) Radio Tower and Shared Data Agreement. Promptly after Closing, the Parties shall cause their Affiliates to enter into a mutually acceptable agreement which allows: (1) Buyer and Affiliates to use the radio tower facilities described in §6(m) of the Disclosure Schedule; and (2) further provides that Cerrito and EGL shall provide, to Buyer’s gas control center, real time pressure, flow and compressor data and, to Buyer’s gas measurement department, daily measurement data including total volumes of gas, each with respect to the Gathering System and in electronic format acceptable to Buyer.

     (n) Joint Use of Easements and Surface Sites. Promptly after Closing, the Parties shall cause their Affiliates to enter into a mutually acceptable agreement providing for their joint use of certain easements and surface leases, as described in §6(n) of the Disclosure Schedule, for both the Gathering System and Sellers’ sour gas system, which is an Excluded Asset.

     (o) Joint Venture Agreement. Promptly after Closing, the Parties shall cause their Affiliates to enter into a mutually acceptable agreement regarding the formation of a joint venture to build certain gathering and compression assets in a mutually agreed area.

§7. Remedies for Breaches of This Agreement

     (a) Indemnification Provisions for Buyer’s Benefit. After Closing, subject to the Claims Period and the limitations in this §7, LEG and the Sellers shall jointly and severally indemnify the Buyer Indemnified Parties from and against any Buyer Adverse Consequences that arise from:

     (i) any Breach of any of the representations or warranties (disregarding any qualification exception contained in such representation or warranty relating to materiality, Material Adverse Effect or Material Adverse Change and disregarding any matter disclosed in §4(e)(i) of the Disclosure Schedule) of Sellers set forth in this Agreement or in any certificate furnished or to be furnished by Sellers in accordance with this Agreement;

     (ii) any Breach or default by any Seller of its covenants or agreements contained in this Agreement;

     (iii) any fraud, willful misconduct or bad faith of any Seller in connection with this Agreement, or any of the Contemplated Transactions;

     (iv) any Excluded Liabilities; and/or

     (v) any Excluded Assets.

     (b) Indemnification Provisions for Sellers’ Benefit. After Closing, subject to the Claims Period and the limitations in this §7, Buyer shall indemnify the Seller Indemnified Parties and LEG from and against any Adverse Consequences that arise from:

     (i) any Breach of any of the representations or warranties of Buyer set forth in this Agreement or the exhibits and schedules hereto, in the Disclosure Schedules, or in any certificate furnished or to be furnished by Buyer in accordance with this Agreement;

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     (ii) any Breach or default by Buyer of its covenants or agreements contained in this Agreement (other than a Breach of Buyer’s covenants in §6(f), which is subject to the indemnity provisions in §6(f));

     (iii) any fraud, willful misconduct or bad faith of Buyer in connection with this Agreement or any of the Contemplated Transactions; and/or

     (iv) Buyer’s failure to perform, discharge or satisfy the Assumed Liabilities.

     (c) Liabilities Non-Recourse to Buyer’s General Partner. Buyer’s Liabilities under this Agreement and under the Transaction Documents to which it is a party are obligations of Buyer only, not the general partner of Buyer. Sellers and LEG agree to limit any claims it may have arising from or connected to this Agreement to Buyer and Buyer’s assets and each Seller waives and releases any related right it may have to pursue or proceed against the general partner of Buyer individually. Notwithstanding the preceding, Sellers may cause legal papers to be served upon any partner of Buyer to the extent necessary and for the sole purpose of obtaining jurisdiction over Buyer.

     (d) Claims Period. The Claims Periods under this Agreement will begin on the Closing Date and terminate as follows:

     (i) with respect to Buyer Adverse Consequences arising: (1) under: §7(a)(i) with respect to any Breach of any Indefinite Surviving Representations; or (2) with respect to the Surviving Indemnification Obligations, the Claims Period will continue indefinitely;

     (ii) with respect to Seller Adverse Consequences arising by virtue of Buyer’s Breach under: (1) §7(b)(i) with respect to §3(a) (Organization), §3(b) (Authorization of Transaction), or §3(c) (Non-contravention); or (2) §7(b)(ii), §7(b)(iii) or §7(b)(iv), the Claims Period will continue indefinitely, except as limited by Law (including any applicable statutes of limitation); and

     (iii) with respect to all other Buyer Adverse Consequences or Seller Adverse Consequences arising under this Agreement, the Claims Period will terminate on the date that is two years after the Closing Date.

Notwithstanding the preceding, if, prior to the close of business on the last day of the applicable Claims Period, an Indemnifying Party has been properly notified of a Claim for Indemnification and that claim has not been finally resolved or disposed of at that date, that Claim for Indemnification will continue to survive and will remain a basis for indemnification under this Agreement until that claim is finally resolved or disposed of in accordance with the terms of this Agreement.

     (e) Buyer Basket; Indemnification. The Buyer Indemnified Parties may not make a Claim for Indemnification against Sellers or LEG unless and until the aggregate amount of those Buyer Adverse Consequences exceeds Five Hundred Thousand Dollars ($500,000) (that amount, the “Basket”), in which event the Buyer Indemnified Parties may claim indemnification for all Buyer Adverse Consequences back to the first dollar. Additionally, the Seller Indemnified

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Parties will have no obligation to indemnify any Buyer Indemnified Party for Buyer Adverse Consequences or otherwise under this Agreement for any amount in excess of 10% of the Base Purchase Price (the “Indemnification Cap”). Notwithstanding the preceding, none of the Indefinite Surviving Representations or the Surviving Indemnification Obligations is subject to the Basket or the Indemnification Cap.

     (f) Determination of Adverse Consequences. All indemnification payments under this §7 shall be paid by the Indemnifying Party without regard to any Tax benefits, insurance coverage, or other indemnification rights that are available to the Indemnified Party, and shall be computed on a present value basis (using the Applicable Rate as the discount rate). All indemnification payments under this §7 shall be deemed adjustments to the Final Purchase Price.

     (g) Exclusive Remedy. THE PARTIES AND LEG ACKNOWLEDGE AND AGREE THAT, FROM AND AFTER THE CLOSING DATE, THE INDEMNIFICATION PROVISIONS IN THIS AGREEMENT ARE THEIR EXCLUSIVE REMEDIES WITH RESPECT TO THIS AGREEMENT, THE EVENTS GIVING RISE THERETO, AND THE CONTEMPLATED TRANSACTIONS. EACH PARTY ACKNOWLEDGES THAT NEITHER IT, NOR ANY SUCCESSOR OR ASSIGN, HAS ANY RIGHTS AGAINST THE OTHER PARTY OR ITS AFFILIATES WITH RESPECT TO THE CONTEMPLATED TRANSACTIONS PROVIDED OTHER THAN AS EXPRESSLY PROVIDED IN THIS AGREEMENT OR IN THE TRANSACTION DOCUMENTS. NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS §7: IN THE EVENT OF A FRAUDULENT OR WILLFUL BREACH OF ANY REPRESENTATION, WARRANTY, COVENANT, OR AGREEMENT CONTAINED HEREIN BY A PARTY, ANY INDEMNIFIED PARTY WILL HAVE ALL REMEDIES AVAILABLE AT LAW OR IN EQUITY (INCLUDING FOR TORT) WITH RESPECT THERETO AND NOT SUBJECT TO ANY LIMITS CONTAINED HEREIN OR IN ANY TRANSACTION DOCUMENT.

     (h) Investigations. The respective representations and warranties of the Parties contained in this Agreement or in any certificate or other document delivered by any Party prior to Closing and the rights to indemnification in this Agreement will not be deemed waived or otherwise affected by any investigation made by a Party.

     (i) Limitation on Damages. NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS AGREEMENT, IN NO EVENT WILL ANY PARTY OR LEG BE LIABLE TO THE OTHER (OR ANY AFFILIATE OR RELATED PERSON) UNDER THIS AGREEMENT FOR ANY EXEMPLARY, PUNITIVE, REMOTE, SPECULATIVE, CONSEQUENTIAL, SPECIAL, OR INCIDENTAL DAMAGES OR LOSS OF PROFITS (OTHER THAN PAYMENT OF SUCH DAMAGES ARISING BY VIRTUE OF LIABILITY TO ANY THIRD PERSON OTHER THAN AN AFFILIATE OR RELATED PERSON HEREUNDER).

§8. Miscellaneous

     (a) No Third-Person Beneficiaries. This Agreement shall not confer any rights or remedies upon any Person other than the Parties and their respective successors and permitted assigns.

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     (b) Disclosure Schedule.

     (i) The information in the Disclosure Schedule constitutes: (1) exceptions to particular representations, warranties, covenants and obligations of Sellers as set forth in this Agreement; or (2) descriptions or lists of Assets and Liabilities and other items referred to in this Agreement. If there is any inconsistency between the statements in this Agreement and those in the Disclosure Schedule (other than an exception expressly set forth as such in the Disclosure Schedule with respect to a specifically identified representation or warranty), the statements in this Agreement will control.

     (ii) The statements in the Disclosure Schedule, and those in any supplement thereto, relate only to the provisions in the Section of this Agreement to which they expressly relate and not to any other provision in this Agreement except as expressly cross-referenced herein.

     (c) Entire Agreement. This Agreement, the Transaction Documents and the Confidentiality Agreement constitute the entire agreement among the Parties and supersede any prior understandings, agreements, or representations by or among the Parties, written or oral, to the extent they relate in any way to the subject matter of this Agreement.

     (d) Succession and Assignment. This Agreement and the Transaction Documents shall be binding upon and inure to the benefit of the Parties named in this Agreement and their respective successors and permitted assigns. No Party may assign either this Agreement or any of its rights, interests, or obligations under this Agreement without the prior written approval of the other Party, except that Buyer may transfer or assign, in whole or from time to time in part, to one or more of its Affiliates (including a Buyer Designee), this Agreement or any Transaction Document or all or any part of its rights or obligations under this Agreement or any Transaction Document. A reference to a Party to this Agreement or another agreement or document includes the Party’s successors and assigns.

     (e) Counterparts. This Agreement may be executed in one or more counterparts (including by means of facsimile), each of which shall be deemed an original but all of which together will constitute one and the same instrument.

     (f) Headings. The section headings contained in this Agreement are inserted for convenience only and shall not affect in any way the meaning or interpretation of this Agreement.

     (g) Notices. Each Party giving or making any notice, request, demand, Consent or other communication (each, a “Notice”) pursuant to this Agreement shall give the Notice in writing and use one of the following methods of delivery each of which for purposes of this Agreement is a writing: (1) personal delivery; (2) registered or certified mail (in each case, return receipt requested and postage prepaid); (3) nationally recognized overnight courier (with all fees prepaid); or (4) facsimile. Any Party giving a Notice shall address the Notice to the appropriate person at the receiving Party at:

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If to any Seller:
	Lewis Energy Group, L.P.
	c/o Tercero Navarro, Inc.
	10101 Reunion Place, Suite 1000
	San Antonio, Texas 78216
	Attn. Rodney R. Lewis
	Facsimile: 210.308.6930
With copies to:
	Al Holcomb
	10101 Reunion Place, Suite 1000
	San Antonio, Texas 78216
	Anthony Trevino, Jr.
	Wilson, Trevino, Freed, Valls & Trevino, LLP
	P.O. Box 420048
	Laredo, Texas 78042-0048
	Facsimile: 956.722.0647
If to Buyer:
	Enterprise Products Partners L.P.
	Attention: President
	1100 Louisiana, Suite 4000
	Houston, Texas 77002
	Facsimile: 713.381.7870
with copies to:
	Enterprise Products Partners L.P.
	Attention: Legal Department
	1100 Louisiana, Suite 4000
	Houston, Texas 77002
	Facsimile: 713.381.7870

Any Party may send any Notice, request, demand, claim, or other communication under this Agreement to the intended recipient at the address set forth above using any other means (including personal delivery, expedited courier, messenger service, telecopy, ordinary mail, or electronic mail), but no such Notice, request, demand, claim, or other communication shall be deemed to have been duly given unless and until it actually is received by the intended recipient. Any Party may change the address to which Notices, requests, demands, claims, and other communications under this Agreement are to be delivered by giving the other Parties Notice in the manner set forth in this Agreement. Except as provided elsewhere in this Agreement, a Notice is effective only if the Party giving the Notice has complied with this §8(g) and the receiving Party has received the Notice. A Notice is deemed to have been received as follows:

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     (i) if a Notice is delivered in person, or sent by registered or certified mail, or national recognized overnight courier, upon receipt as indicated by the date on the signed receipt;

     (ii) if a Notice is sent by facsimile, upon receipt by the Party giving or making the Notice of an acknowledgment or transmission report generated by the machine from which the facsimile was sent indicating that the facsimile was sent in its entirety to the recipient’s facsimile number; or

     (iii) if the receiving Party rejects or otherwise refuses to accept the Notice, or if the Notice cannot be delivered because of a change in address for which no Notice was given, then upon the rejection, refusal or inability to deliver; and

     (iv) despite §8(g)(i) through §8(g)(iii), if any Notice is received after 5 p.m. on a Business Day where the recipient is located, or on a day that is not a Business Day where the recipient is located, then the Notice is deemed received at 9:00 a.m. on the next Business Day where the recipient is located.

     (h) Governing Law. This Agreement shall be governed by and construed in accordance with the domestic Laws of the State of Texas without giving effect to any choice or conflict of Law provision or rule (whether of the State of Texas or any other jurisdiction) that would cause the application of the Laws of any jurisdiction other than the State of Texas.

     (i) Arbitration. Any dispute, controversy, or claim arising out of or relating to this Agreement (a “Dispute”) shall be settled by binding arbitration in accordance with the commercial arbitration rules of the American Arbitration Association. Any such Dispute shall be arbitrated on an individual basis, and shall not be consolidated in any arbitration with any dispute, claim, or controversy of any other Party. The arbitration shall be conducted in the English language in San Antonio, Texas, and any court having jurisdiction thereof may immediately issue judgment on the arbitration award. The Parties agree that the arbitration provided for in this §8(i) shall be the exclusive means to resolve all Disputes and the arbitrator shall be empowered to grant specific performance or other equitable remedies to a Party.

     (j) Amendments and Waivers. No amendment of any provision of this Agreement shall be valid unless the same shall be in writing and signed by Buyer and the Seller Representative. No waiver by any Party of any provision of this Agreement or any default, misrepresentation, or Breach of warranty or covenant under this Agreement, whether intentional or not, shall be valid unless the same shall be in writing and signed by the Party making such waiver, nor shall such waiver be deemed to extend to any prior or subsequent default, misrepresentation, or Breach of warranty or covenant under this Agreement or affect in any way any rights arising by virtue of any prior or subsequent such occurrence.

     (k) Seller Representative. By signing this Agreement, Sellers hereby irrevocably constitute and appoint Rodney R. Lewis as the true and lawful agent and attorney-in-fact (the “Seller Representative”) with full powers of substitution to act in the name, place and stead of Sellers with respect to the performance on behalf of Sellers under this Agreement, and to do or refrain from doing all such further acts and things, and to execute all such documents, as the

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Seller Representative deems necessary or appropriate in connection with any of the Contemplated Transactions, including to: (1) accept and give Notices under this Agreement on behalf of any or all of the Sellers; (2) Consent to any modification or amendment of this Agreement; and (3) give any waiver or Consent under this Agreement. Sellers Representative does hereby accept such appointment. Buyer shall be entitled to rely exclusively upon such Notices, Consents, amendments, modifications and other acts of the Seller Representative as being the binding acts of the Sellers or any of them, and Buyer shall be entitled to deliver any Notices, payments or other items required to be delivered by it to any Seller under this Agreement only to the Seller Representative, and any such delivery will be fully effective as if it were made directly to any relevant Seller.

     (l) Severability. Any term or provision of this Agreement that is invalid or unenforceable in any situation in any jurisdiction shall not affect the validity or enforceability of the remaining terms and provisions of this Agreement or the validity or enforceability of the offending term or provision in any other situation or in any other jurisdiction.

     (m) Expenses. Except as otherwise provided in this §8(m), each of Buyer, on the one hand, and Sellers, on the other hand, will bear its own costs and expenses (including legal fees and expenses) incurred in connection with this Agreement and the Contemplated Transactions. All transfer, documentary, sales, use, stamp, registration and other such Taxes, and all conveyance fees, recording charges and other similar fees and charges (including any penalties and interest) incurred in connection with the consummation of the Contemplated Transactions shall be paid by Buyer when due, and Buyer shall, at its own expense, file all necessary Tax Returns and other documentation with respect to all such Taxes, fees and charges, and, if required by applicable Law, the Parties will, and will cause their Affiliates to, join in the execution of any such Tax Returns and other documentation. Notwithstanding the foregoing, Sellers, on the one hand, and Buyer, on the other hand, shall each pay their respective filing fees under the HSR Act, and all ad valorem Taxes for the year 2006 shall be prorated as of the Effective Time between Buyer and Sellers.

     (n) Construction. The Parties have participated jointly in the negotiation and drafting of this Agreement. If an ambiguity or question of intent or interpretation arises, then this Agreement shall be construed as if drafted jointly by the Parties and no presumption or burden of proof shall arise favoring or disfavoring any Party by virtue of the authorship of any of the provisions of this Agreement. All references in this Agreement to articles, sections or subdivisions thereof shall refer to the corresponding article, section, or subdivision thereof of this Agreement unless specific reference is made to such articles, sections, or subdivisions of another document or instrument. Any reference to any federal, state, local, or foreign statute or Law shall be deemed also to refer to all rules and regulations promulgated thereunder, unless the context requires otherwise. The word “including” means including without limitation.

     (o) Incorporation of Exhibits and Schedules. The Exhibits and Schedules identified in this Agreement are incorporated in this Agreement by reference and made a part of this Agreement.

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     (p) Bold and/or Capitalized Letters. THE PARTIES AGREE THAT THE BOLD AND/OR CAPITALIZED LETTERS IN THIS AGREEMENT CONSTITUTE CONSPICUOUS LEGENDS.

     (q) 1031 Treatment. Sellers may have elected prior to Closing, that Buyer direct all or a portion of the Estimated Purchase Price be delivered to a “qualified intermediary” (as defined in Treasury Regulation Section 1.1031(k)-(g)(4)) to enable the applicable Sellers’ deemed relinquishment of the Assets) to qualify as part of a like-kind exchange of property covered by Section 1031 of the Code. If Sellers have so elected, Buyer shall cooperate with Sellers (but without being required to incur any out-of-pocket costs in the course thereof) in connection with their efforts to effect such like-kind exchange, which cooperation shall include, taking such actions as the applicable Seller requests in order to enable such Seller to qualify such transfer as part of a like-kind exchange of property covered by Section 1031 of the Code (including any actions required to facilitate the use of a “qualified intermediary”). Additionally, consistent with Treasury Regulation §1.1031(k)-1(g)(4)(v), Buyer agrees that the applicable Seller may assign all or part of its rights under this Agreement to a Person acting as a qualified intermediary to qualify the transfer of the Assets and agrees to notify Buyer in writing of the assignment on or before the Closing Date. Buyer and Sellers agree to use reasonable commercial efforts to coordinate the Contemplated Transactions with any other transactions engaged in by either Buyer or Sellers. The Parties agree that the amount of cash deposited with a qualified intermediary that is allocated to any particular Asset designated by Sellers as a ‘relinquished property’ shall not exceed 45% of the fair market value of such Asset, as determined by the allocation of Final Purchase Price described in §2(g). Any excess cash remaining in a qualified intermediary account after Sellers have allocated such cash among all of the Assets they wish to treat as part of a like-kind exchange will be released to Sellers and allocated among all of the other purchased Assets.

[The signatures are on the next page.]

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     The Parties are signing this Agreement on June 12, 2006.

LEG:	LEWIS ENERGY GROUP, L.P.
		By: Tercero Navarro, Inc., general partner
			By:	/s/ Rodney R. Lewis
				Rodney R. Lewis
				President
CERRITO:	CERRITO GATHERING COMPANY, LTD.
		By: Tercero Navarro, Inc., general partner
			By:	/s/ Rodney R. Lewis
				Rodney R. Lewis
				President
CGM:	CERRITO GAS MARKETING, LTD.
		By: Tercero Navarro, Inc., general partner
			By:	/s/ Rodney R. Lewis
				Rodney R. Lewis
				President
EGL:	ENCINAL GATHERING, LTD.
		By: Tercero Navarro, Inc., general partner
			By:	/s/ Rodney R. Lewis
				Rodney R. Lewis
				President
BUYER:	ENTERPRISE PRODUCTS PARTNERS L.P.
		By: Enterprise Products GP, LLC, general partner
			By:	/s/ James H. Lytal
				James H. Lytal
				Executive Vice President

[ Signatures page to Cerrito purchase agreement dated July 12, 2006.]

EX-31.1

EXHIBIT 31.1

CERTIFICATIONS

	I, Robert G. Phillips, certify that:
1.	I have reviewed this quarterly report on Form 10-Q of Enterprise Products Partners L.P.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 8, 2006

/s/ Robert G. Phillips
Name:	Robert G. Phillips
Title:	Principal Executive Officer of our General Partner, Enterprise Products GP, LLC

EX-31.2

EXHIBIT 31.2

CERTIFICATIONS

	I, Michael A. Creel, certify that:
1.	I have reviewed this quarterly report on Form 10-Q of Enterprise Products Partners L.P.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 8, 2006

/s/ Michael A. Creel
Name:	Michael A. Creel
Title:	Principal Financial Officer of our General Partner, Enterprise Products GP, LLC

EX-32.1

EXHIBIT 32.1

SARBANES-OXLEY SECTION 906 CERTIFICATION

CERTIFICATION OF ROBERT G. PHILLIPS, CHIEF EXECUTIVE OFFICER
OF ENTERPRISE PRODUCTS GP, LLC, THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS PARTNERS L.P.

          In connection with this quarterly report of Enterprise Products Partners L.P. (the “Registrant”) on Form 10-Q for the quarterly period ended June 30, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert G. Phillips, Chief Executive Officer of Enterprise Products GP, LLC, the general partner of the Registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Robert G. Phillips
Name:	Robert G. Phillips
Title:	Chief Executive Officer of Enterprise Products GP, LLC on behalf of Enterprise Products Partners L.P.
Date:	August 8, 2006

EX-32.2

EXHIBIT 32.2

SARBANES-OXLEY SECTION 906 CERTIFICATION

CERTIFICATION OF MICHAEL A. CREEL, CHIEF FINANCIAL OFFICER
OF ENTERPRISE PRODUCTS GP, LLC, THE GENERAL PARTNER OF
ENTERPRISE PRODUCTS PARTNERS L.P.

          In connection with this quarterly report of Enterprise Products Partners L.P. (the “Registrant”) on Form 10-Q for the quarterly period ended June 30, 2006 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael A. Creel, Chief Financial Officer of Enterprise Products GP, LLC, the general partner of the Registrant, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Michael A. Creel
Name:	Michael A. Creel
Title:	Chief Financial Officer of Enterprise Products GP, LLC on behalf of Enterprise Products Partners L.P.
Date:	August 8, 2006