SEC Filing | Enterprise Products Partners L.P.

Title of Each Class of

Proposed Maximum

Securities to be Registered

Aggregate Offering Price(1)(2)

Amount of Registration Fee

Common units representing limited partner interests

$313,950,000

View:

Download DOC

Download PDF

Download XLS

sv1

As filed with the Securities and Exchange Commission on November 2, 2006

Registration No. 333-

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Duncan Energy Partners L.P.

(Exact Name of Registrant as Specified in Its Charter)


Delaware	4922	20-5639997
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

1100 Louisiana Street, 10th Floor

Houston, Texas 77002

(713) 381-6500

(Address, Including Zip Code, and Telephone Number, Including

Area Code, of Registrant’s Principal Executive Offices)

Richard H. Bachmann

1100 Louisiana Street, 10th Floor

Houston, Texas 77002

(713) 381-6500

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

Copies to:


Robert V. Jewell David C. Buck Andrews Kurth LLP 600 Travis, Suite 4200 Houston, Texas 77002 (713) 220-4200		Joshua Davidson Sean T. Wheeler Baker Botts L.L.P. One Shell Plaza, 910 Louisiana Houston, Texas 77002 (713) 229-1234

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

CALCULATION OF REGISTRATION FEE


(1)		Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2)		Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, dated November 2, 2006

PROSPECTUS

13,000,000 Common Units

Representing Limited Partner Interests

Duncan Energy Partners L.P. is a limited partnership recently formed by Enterprise Products Partners L.P. This is the initial public offering of our common units. We currently estimate that the initial public offering price will be between $ and $ per common unit. Before this offering, there has been no public market for our common units. We intend to apply to list the common units on the New York Stock Exchange under the symbol “DEP.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 22.

These risks include the following:


•	We may not have sufficient cash from operations to enable us to pay distributions on our common units.

•	Changes in demand for and production of hydrocarbon products may materially adversely affect our results of operations, cash flows and financial condition.

•	We depend on Enterprise Products Partners L.P. and certain other key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash from operations available to pay distributions to our unitholders.

•	Our general partner and its affiliates, including Enterprise Products Partners L.P., will have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.

•	Affiliates of our general partner, including Enterprise Products Partners L.P., Enterprise GP Holdings L.P. and TEPPCO Partners L.P., may compete with us and be entitled to pursue certain business opportunities before us. This arrangement may limit our ability to grow.

•	Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

•	Unitholders have limited voting rights and are not entitled to elect our general partner or its directors.

•	You will experience immediate and substantial dilution of $ per unit in the net tangible book value of your common units.

•	You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.


	Per Common Unit	Total

Initial public offering price	$	$
Underwriting discount(1)	$	$
Proceeds to us before expenses	$	$


(1)		Excludes structuring fee payable to Lehman Brothers of $ , in consideration of advice rendered by Lehman Brothers related to this offering and related transactions.

We have granted the underwriters a 30-day option to purchase up to an additional 1,950,000 common units on the same terms and conditions as set forth above, if the underwriters sell more than 13,000,000 common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about , 2007.

Lehman Brothers

, 2007

TABLE OF CONTENTS


SUMMARY			1
Duncan Energy Partners L.P.			1
The Offering			6
Summary of Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties			9
Summary of Certain Risk Factors			12
Summary Historical and Pro Forma Financial and Operating Data			14
RISK FACTORS			22
Risks Inherent in Our Business			22
Risks Inherent in an Investment in Us			35
Tax Risks			42
USE OF PROCEEDS			45
CAPITALIZATION			46
DILUTION			47
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			49
General			49
Our Initial Distribution Rate			50
Unaudited Pro Forma Combined Available Cash			52
Estimated Cash Available to Pay Distributions			54
Assumptions and Considerations			56
HOW WE MAKE CASH DISTRIBUTIONS			60
Distributions of Available Cash			60
Distributions of Cash upon Liquidation			60
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			62
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			68
Overview			68
Our Operations			69
How We Evaluate Our Operations			71
Natural Gas Supply and Outlook			73
Factors Affecting Comparability of Future Results			73
Results of Operations			75
Liquidity and Capital Resources			77
Contractual Obligations			82
Off-Balance Sheet Arrangements			83
Inflation			84
Seasonality			84
Critical Accounting Policies and Estimates			84
Recent Accounting Developments			87
Related Party Transactions			88
Other Items			89
Quantitative and Qualitative Disclosures about Market Risk			90


BUSINESS			92
Our Partnership			92
Our Relationship with EPCO and Enterprise Products Partners			92
Our Business Strategy			93
Our Competitive Strengths			93
Industry Overview			94
NGL & Petrochemical Storage Services Segment			96
Natural Gas Pipelines & Services Segment			99
Petrochemical Pipeline Services Segment			104
NGL Pipeline Services Segment			105
Supplies			106
Employees			107
Environmental Matters			107
Regulation of Operations			109
Title to Properties			110
Legal Proceedings			110
MANAGEMENT			111
General			111
Governance Matters			111
Directors and Executive Officers			114
Executive Compensation			115
Compensation of Directors of DEP Holdings			116
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			117
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			118
Our Relationship with EPCO and Enterprise Products Partners			118
Related Party Transactions with Enterprise Products Partners			118
Relationships with TEPPCO Partners			120
Relationships with Unconsolidated Affiliate			120
Contribution, Conveyance and Assumption Agreement			120
Omnibus Agreement			121
Mont Belvieu Caverns Limited Liability Company Agreement			122
Administrative Services Agreement			123
CONFLICTS OF INTEREST, BUSINESS OPPORTUNITY AGREEMENTS AND FIDUCIARY DUTIES			126
Conflicts of Interest and Business Opportunity Agreements			126
Fiduciary Duties			129
DESCRIPTION OF OUR COMMON UNITS			132
Transfer Agent and Registrar			132
Transfer of Units			132
DESCRIPTION OF MATERIAL PROVISIONS OF OUR PARTNERSHIP AGREEMENT			134
Organization and Duration			134
Purpose			134
Power of Attorney			134
Cash Distributions			134
Capital Contributions			134


Limited Liability			135
Voting Rights			135
Issuance of Additional Securities			136
Amendments to Our Partnership Agreement			137
Merger, Sale or Other Disposition of Assets			139
Termination or Dissolution			139
Liquidation and Distribution of Proceeds			140
Withdrawal or Removal of Our General Partner			140
Transfer of General Partner Interest			141
Transfer of Ownership Interests in Our General Partner			141
Change of Management Provisions			141
Limited Call Right			142
Meetings; Voting			142
Status as Limited Partner			143
Non-Citizen Assignees; Redemption			143
Indemnification			143
Resolution of Conflicts of Interest			143
Reimbursement of Expenses			144
Books and Reports			145
Right to Inspect Our Books and Records			145
Registration Rights			145
COMMON UNITS ELIGIBLE FOR FUTURE SALE			146
MATERIAL TAX CONSEQUENCES			147
Partnership Status			147
Limited Partner Status			148
Tax Consequences of Unit Ownership			149
Tax Treatment of Operations			153
Disposition of Common Units			154
Uniformity of Units			156
Tax-Exempt Organizations and Other Investors			157
Administrative Matters			157
State, Local and Other Tax Considerations			159
SELLING UNITHOLDER			161
UNDERWRITING			162
VALIDITY OF THE COMMON UNITS			167
EXPERTS			167
WHERE YOU CAN FIND MORE INFORMATION			167
FORWARD-LOOKING STATEMENTS			168
INDEX TO FINANCIAL STATEMENTS			F-1
APPENDIX A — FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF DUNCAN ENERGY PARTNERS L.P.			A-1
APPENDIX B — GLOSSARY OF TERMS			B-1
Certificate of Limited Partnership of Duncan Energy Partners L.P.
Certificate of Formation of DEP Holdings, LLC
Certificate of Formation of DEP OLPGP, LLC
Certificate of Limited Partnership of DEP Operating Partnership, L.P.
Consent of Deloitte & Touche LLP

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized any other person to provide you with different information. If anyone provides you with

iii

different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition and results of operations may have changed since that date.

Until , 2007 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. You should read “Risk Factors” for important information about risks that you should consider before buying our common units. The information presented in this prospectus assumes an initial public offering price per unit of $ and that the underwriters’ option to purchase additional common units is not exercised, unless otherwise noted.

All references in this prospectus to “we,” “us,” “Duncan Energy Partners,” the “Partnership” and “our” refer to Duncan Energy Partners L.P. and its subsidiaries. All references in this prospectus to “we,” “us,” “our” or the “Company,” when used in a historical context, are intended to mean and include the combined business and operations of Duncan Energy Partners Predecessor. Duncan Energy Partners Predecessor reflects ownership of 100% of the assets being contributed, but we will own only a 66% interest in these assets after their contribution in connection with this offering. For all references in this prospectus to the terms “our general partner,” “DEP Holdings,” “Enterprise Products Partners,” “Enterprise Products OLP,” “Enterprise Products GP,” “Enterprise GP Holdings,” “EPE Holdings,” “EPCO,” “Mont Belvieu Caverns,” “Acadian Gas,” “Sabine Propylene,” “Lou-Tex Propylene,” “South Texas NGL,” “TEPPCO Partners,” “TEPPCO GP” and “Evangeline,” please read Appendix B — Glossary of Terms. Please also read Appendix B — Glossary of Terms for a glossary of industry and partnership terms used in this prospectus.

Duncan Energy Partners L.P.

We are a Delaware limited partnership formed by Enterprise Products Partners in September 2006 to own, operate and acquire a diversified portfolio of midstream energy assets. We are engaged in the business of gathering, transporting, marketing and storing natural gas and transporting and storing natural gas liquids, or NGLs, and petrochemicals. Our assets were previously owned by Enterprise Products Partners and are part of its integrated midstream energy asset network, or “value chain,” which includes natural gas gathering, processing, transportation and storage; NGL fractionation (or separation), transportation, storage and import and export terminaling; crude oil transportation; and offshore production platform services. After this offering, we will own 66% of the equity interests in the subsidiaries that hold our operating assets, and affiliates of Enterprise Products Partners will continue to own the remaining 34%. We believe our relationship with Enterprise Products Partners will enable us to maintain stable cash flows and optimize our scale, strategic location and pipeline connections.

Our operations are organized into the following four business segments:


	•	NGL & Petrochemical Storage Services. Our NGL & Petrochemical Storage Services segment consists of 33 salt dome caverns located in Mont Belvieu, Texas, with an underground storage capacity of approximately 100 MMBbls, and certain related assets. These assets receive, store and deliver NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States.

	•	Natural Gas Pipelines & Services. Our Natural Gas Pipelines & Services segment consists of the Acadian Gas system, which is an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. In the aggregate, the Acadian Gas system includes over 1,000 miles of high-pressure transmission lines and lateral and gathering lines with an aggregate throughput capacity of approximately one Bcf/d and a leased storage facility with approximately three Bcf of storage capacity.

	•	Petrochemical Pipeline Services. Our Petrochemical Pipeline Services segment consists of two petrochemical pipeline systems with an aggregate of 284 miles of pipeline. The Lou-Tex propylene pipeline system consists of a 263-mile pipeline used to transport chemical-grade propylene between


		Sorrento, Louisiana and Mont Belvieu, Texas. The Sabine propylene pipeline system consists of a 21-mile pipeline used to transport polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect in Cameron Parish, Louisiana on a transport-or-pay basis.


	•	NGL Pipeline Services. Our NGL Pipeline Services segment will consist of a 290-mile pipeline system used to transport NGLs from two Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas and related interconnections. We acquired a 223-mile segment of the system in August 2006, and we are in the process of acquiring and constructing other segments of the pipeline. The system is not in operation, but it is currently undergoing modifications, extensions and interconnections that should allow it to transport NGLs beginning in January 2007. Additional expansions are scheduled to be completed during 2007.

Our Relationship With Enterprise Products Partners

Enterprise Products Partners is a North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, NGLs and crude oil, and is an industry leader in the development of pipeline and other midstream infrastructure in the continental United States and Gulf of Mexico. Enterprise Products Partners’ value chain is an integrated midstream energy asset network that links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States, Canada and the Gulf of Mexico with domestic consumers and international markets. For the year ended December 31, 2005, Enterprise Products Partners had revenues of $12.3 billion, operating income of $663 million and net income of $420 million. For the six months ended June 30, 2006, Enterprise Products Partners had revenues of $6.8 billion, operating income of $379.5 million and net income of $260 million.

In the event we propose to sell any equity interests in our operating subsidiaries or material assets of those entities, other than sales of inventory and other assets in the ordinary course of business, Enterprise Products OLP will have a right of first refusal to purchase those interests or assets. We believe our relationship with EPCO and Enterprise Products Partners will provide us access to a significant pool of management talent and strong commercial relationships throughout the energy industry; however, this relationship is also a source of potential conflicts. For example, Enterprise Products Partners, EPCO and their affiliates are not restricted from competing with us and may generally acquire, construct or dispose of midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets or participate in these activities. Please read “Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties” and “Certain Relationships and Related Party Transactions — Administrative Services Agreement” for more information.

Our Business Strategy

Our primary objectives are to maintain and, over time, to increase our cash available for distributions to our unitholders. Our business strategies to achieve these objectives are to:


	•	optimize the benefits of our scale, strategic location and pipeline connections serving our natural gas, NGL, petrochemical and refining markets;

	•	manage our existing and future asset portfolio to minimize the volatility of our cash flows;

	•	invest in organic growth projects to capitalize on market opportunities which expand our asset base and generate additional cash flow; and

	•	pursue acquisitions of assets and businesses from related parties or, in accordance with our business opportunity agreements, from third parties.

For a description of our business opportunity agreements, please read “— Summary of Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties” and “Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties.”

Our Competitive Strengths

We believe we are well-positioned to achieve our primary objectives and to execute our business strategies successfully because of the following competitive strengths:


	•	our operations currently consist of mature assets and a new NGL pipeline which are expected to generate stable, predictable cash flows;

	•	our assets are strategically located in areas with high demand for our services and play a critical role in Enterprise Products Partners’ midstream energy value chain;

	•	Enterprise Products Partners and EPCO have established a reputation in the midstream natural gas and NGL industries as reliable and cost-effective operators;

	•	the senior management team and board of directors of our general partner have extensive industry experience and include some of the most senior officers of EPCO;

	•	we have a lower cost of capital than other publicly traded partnerships that have incentive distribution rights; and

	•	our affiliation with Enterprise Products Partners and its affiliates may provide us access to attractive acquisition opportunities from them and third parties.

Formation Transactions

At the closing of this offering, the following transactions will occur:


	•	Enterprise Products OLP will contribute to us 66% of the equity interests in Mont Belvieu Caverns, Acadian Gas, Sabine Propylene, Lou-Tex Propylene and South Texas NGL;

	•	We will issue to Enterprise Products OLP 7,298,551 common units representing an approximate 35.2% limited partner interest in us (or an approximate 25.8% limited partner interest if the underwriters exercise in full their option to purchase additional common units), and we will issue a 2% general partner interest to our general partner, DEP Holdings, LLC;

	•	We will borrow approximately $200 million under a new credit agreement that we anticipate entering into prior to the closing of this offering, which will be used to fund a portion of our payment to Enterprise Products Partners in connection with the transactions described above;

	•	We will sell 13,000,000 common units to the public in this offering representing an approximate 62.8% limited partner interest in us (or an approximate 72.2% limited partner interest if the underwriters exercise in full their option to purchase additional common units), and will use the net proceeds from this offering as described under “Use of Proceeds;”

	•	We will become party to an existing administrative services agreement among EPCO and certain of their affiliates;

	•	We will enter into various new transportation, storage and operating agreements with Enterprise Products OLP and its affiliates; and

	•	We will enter into an omnibus agreement with Enterprise Products Partners, pursuant to which Enterprise Products Partners will agree to (i) indemnify us for certain environmental liabilities, tax liabilities and title and right-of-way defects occurring or existing before the closing and (ii) reimburse us for our 66% share of excess construction costs, if any, above our current estimated cost to complete planned expansions on the South Texas NGL pipeline.

Management and Ownership

As is common with publicly traded limited partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries.

Our general partner will manage our operations and activities. Some of the executive officers and non-independent directors of our general partner also serve as executive officers or directors of Enterprise Products GP, EPE Holdings and TEPPCO GP. Please read “Management.” Our general partner will not receive any management fee or other compensation in connection with its management of our business but will be entitled to be reimbursed for all direct and indirect expenses incurred on our behalf. Neither our general partner nor the board of directors of our general partner will be elected by our unitholders. Unlike shareholders in a corporation, our unitholders will not elect or remove the board of directors of our general partner.

Our principal executive offices are located at 1100 Louisiana Street, 10th Floor, Houston, Texas 77002, and our telephone number is (713) 381-6500. Our website is located at http://www.deplp.com. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Our Structure

The following diagram depicts our organizational structure after giving effect to this offering and the related transactions assuming no exercise of the underwriters’ option to purchase additional common units.

Ownership of Duncan Energy Partners L.P.


			% of
			Total
	Common Units		Ownership
Public common units		13,000,000		62.8	%
Enterprise Products Partners and its affiliates		7,298,551		35.2	%
General partner interest		—		2.0	%

Total		20,298,551		100.0	%

The Offering


Common units offered		13,000,000 common units.

Common units subject to the underwriters’ option to purchase additional common units		If the underwriters exercise their option to purchase additional units in full, we will issue 1,950,000 additional common units to the public and redeem 1,950,000 common units from Enterprise Products OLP, who may be deemed to be a selling unitholder in this offering. Please read “Selling Unitholder.”

Common units outstanding after this offering		20,298,551 common units.

Use of proceeds		We will use the net proceeds from this offering of approximately $243.4 million (based on an assumed offering price of $20.00 per unit), after deducting the underwriting discount and a structuring fee, but before estimated expenses associated with the offering and related formation transactions, to:

		• distribute approximately $221 million to Enterprise Products OLP as a portion of the cash consideration and reimbursement for capital expenditures relating to the assets contributed to us;

		• provide approximately $20.4 million to fund our share of estimated capital expenditures to complete planned expansions to the South Texas NGL pipeline subsequent to the closing of this offering; and

		• pay $2 million of estimated net expenses associated with this offering and related formation transactions.

		In addition, we will borrow approximately $200 million under a new credit agreement that we will enter into prior to the closing of this offering, and we will distribute $198 million of these borrowings to Enterprise Products OLP in partial consideration for the assets contributed to us upon the closing of this offering.

		If the underwriters exercise their option to purchase additional common units, we will use all of the net proceeds from the sale of those common units to redeem an equal number of common units from Enterprise Products OLP. For the resulting beneficial ownership, read “Security Ownership of Certain Beneficial Owners and Management.”

Cash distributions		We intend to make initial quarterly distributions of $0.40 per common unit to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to our general partner. We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement as summarized in “How We Make Cash Distributions — Distributions of Available Cash — Definition of Available Cash.” The amount of available cash may be greater than or less than the aggregate amount associated with payment of the expected initial quarterly distribution on all common units. In


		general, we will pay 98% of any cash distributions we make each quarter to our unitholders and the remaining 2% to our general partner.

		Unlike many publicly traded limited partnerships, our general partner is not entitled to any incentive distributions and we do not have any subordinated units.

		We believe that, based on the assumptions and considerations described in “Cash Distribution Policy and Restrictions on Distributions — Assumptions and Considerations,” we will have sufficient available cash to pay the full initial quarterly distribution on all our common units and our general partner interest for each quarter during the four quarters ending December 31, 2007. We estimate that our pro forma available cash for the year ended December 31, 2005 would have been sufficient to pay only 30% of the initial quarterly distributions on our common units and our general partner interest during that period. We estimate that our pro forma available cash for the four quarters ended June 30, 2006 would not have been sufficient to pay any distributions on our common units and our general partner interest.

		We will pay investors in this offering a prorated distribution for the first quarter during which we are a publicly traded partnership. This distribution will be paid for the period beginning on the first day our common units are publicly traded and ending on the last day of that fiscal quarter. Therefore, we will pay investors in this offering a distribution for the period from the closing date of this offering to and including March 31, 2007. We expect to pay this cash distribution on or about May 15, 2007.

Limited call right		If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units.

Issuance of additional units		We can issue an unlimited number of units without the consent of our unitholders. Please read “Common Units Eligible For Future Sale” and “Description of Material Provisions of Our Partnership Agreement — Issuance of Additional Securities.”

Limited voting rights		Our general partner will manage all of our operations. Unlike the holders of common stock of a corporation, you will have only limited voting rights on matters affecting our business and you will have no right to elect our general partner or its officers or directors. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding common units, including common units owned by our general partner and its affiliates. Upon completion of this offering, affiliates of our general partner will own approximately 36.0% of our outstanding common units (or approximately 26.3% of our outstanding common units if the underwriters’ option to purchase additional common units is exercised in full). Please read “Description of Material Provisions of Our Partnership Agreement — Withdrawal or Removal of Our General Partner.”


Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through December 31, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash distributed with respect to that period. For example, if you receive an annual distribution of $ per common unit, we estimate that your average allocated federal taxable income per year will be no more than $ per unit. Please read “Material Tax Consequences” in this prospectus for the basis of this estimate.

Material tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

Exchange listing		We intend to apply to list our common units on the New York Stock Exchange under the symbol “DEP.”

Summary of Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties

The following diagram summarizes the current organizational structure of EPCO, affiliates of Dan L. Duncan and our affiliates at September 30, 2006.

General. Conflicts of interest exist and may arise in the future as a result of the relationships among us, Enterprise Products Partners, Enterprise GP Holdings, TEPPCO Partners and our and their respective general partners and affiliates. Our general partner is controlled indirectly by Enterprise Products Partners. Mr. Dan L. Duncan has the ability to elect, remove and replace the directors and officers of our general partner and the general partners of Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners. The assets of Enterprise Products Partners, Enterprise GP Holdings, TEPPCO Partners and us overlap in certain areas, which may result in various conflicts of interest in the future.

The directors and officers of our general partner have fiduciary duties to manage our business in a manner beneficial to us and our partners. Some of the executive officers and non-independent directors of our general partner also serve as executive officers or directors of Enterprise Products GP, EPE Holdings and TEPPCO GP. As a result, they have fiduciary duties to manage the business of each of those entities in a manner beneficial to such entities and their respective partners. Consequently, these directors and officers may

encounter situations in which their fiduciary obligations to Enterprise Products Partners, Enterprise GP Holdings or TEPPCO Partners, on the one hand, and us, on the other hand, are in conflict. For a more detailed description of the conflicts of interest involving our general partner, please read “Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties.”

Business Opportunity Agreements under our Administrative Services Agreement. At or prior to the closing of this offering, we and our general partner will become party to an existing administrative services agreement with EPCO, Enterprise Products Partners and its general partner, Enterprise GP Holdings and its general partner, TEPPCO Partners and its general partner, and certain affiliated entities. The administrative services agreement will address potential conflicts that may arise among us and our general partner, Enterprise Products Partners and its general partner, Enterprise GP Holdings and its general partner, TEPPCO Partners and its general partner, and the EPCO Group, which includes EPCO and its affiliates but does not include the aforementioned entities and their controlled affiliates.

The administrative services agreement will provide, among other things, that:


	•	if a business opportunity to acquire certain equity securities (which we define to include general partner interests in publicly traded partnerships and similar interests and any associated incentive distribution rights, limited partner interests or similar interests owned by the owner of such general partner interest or its affiliates), is presented to the EPCO Group, us, and our general partner, Enterprise Products Partners and its general partner, or Enterprise GP Holdings and its general partner, Enterprise GP Holdings will have the first right to pursue the acquisition. In the event that Enterprise GP Holdings abandons the acquisition, Enterprise Products Partners will have the second right to pursue such acquisition either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of us. In the event that Enterprise Products Partners affirmatively directs the acquisition to us, we may pursue such acquisition. In the event that Enterprise Products Partners abandons the acquisition for itself and for us, the EPCO Group may pursue the acquisition without any further obligation to any other party or offer such opportunity to other affiliates; and

	•	if any business opportunity not covered by the preceding bullet point is presented to the EPCO Group, us and our general partner, Enterprise Products Partners and its general partner, or Enterprise GP Holdings and its general partner, Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of us. In the event that Enterprise Products Partners affirmatively directs the business opportunity to us, we may pursue such business opportunity. In the event Enterprise Products Partners abandons the business opportunity for itself and for us, Enterprise GP Holdings will have the second right to pursue such business opportunity. In the event Enterprise GP Holdings abandons the business opportunity, the EPCO Group may pursue the business opportunity without any further obligation to any other party or offer such opportunity to other affiliates.

None of the EPCO Group, we and our general partner, Enterprise Products Partners and its general partner, or Enterprise GP Holdings and its general partner will have any obligation to present business opportunities to TEPPCO Partners, its general partner or their controlled affiliates, nor will TEPPCO Partners, its general partner or their controlled affiliates have any obligation to present business opportunities to the EPCO Group, us and our general partner, Enterprise Products Partners and its general partner, or Enterprise GP Holdings and its general partner. For a more detailed description of these provisions, please read “Certain Relationships and Related Party Transactions — Administrative Services Agreement.”

Shared Personnel. DEP Holdings, as our general partner, will manage our operations and activities. Under the administrative services agreement, EPCO will provide all employees and administrative, operational and other services for us. All of our general partner’s executive officers will, and certain other EPCO employees assigned to our operations may, also perform services for EPCO, Enterprise Products Partners,

Enterprise GP Holdings, TEPPCO Partners and their affiliates. The services performed by these shared personnel will generally be limited to non-commercial functions, including but not limited to human resources, information technology, financial and accounting services and legal services. We have adopted policies and procedures intended to protect and prevent inappropriate disclosure by shared personnel of commercial and other non-public information relating to us, EPCO, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners.

Because our general partner’s executive officers allocate time among EPCO, us, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners, these officers face conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

Compensation Arrangements. Dan L. Duncan, as the control person of EPCO, our general partner and the general partners of Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners, is responsible for establishing the compensation arrangements for all EPCO employees, including employees who provide services to us, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners.

Fiduciary Duties. Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner and its affiliates to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions that might otherwise constitute a breach of our general partner’s and its affiliates’ fiduciary duty owed to unitholders. By purchasing our common units, you are treated as having consented to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law. Please read “Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties — Fiduciary Duties” for a description of the fiduciary duties imposed on our general partner by Delaware law, the material modifications of these duties contained in our partnership agreement and certain legal rights and remedies available to unitholders.

For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

Summary of Certain Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. The following list of risk factors is not exhaustive. For more information about these and other risks, please read “Risk Factors” beginning on page 22. These risks include, among others:

Risks Inherent in Our Business


	•	We may not have sufficient cash from operations to enable us to pay our expected initial quarterly distribution on our common units or to increase our distributions.

	•	A decrease in demand for natural gas, NGLs, NGL products and petrochemical products by the petrochemical, refining or heating industries could materially adversely affect our results of operations, cash flows and financial position.

	•	A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow and, accordingly, affect the market price of our common units.

	•	We may be limited in our ability to make acquisitions or may be unable to make acquisitions on economically acceptable terms.

	•	Federal, state or local regulatory measures could materially adversely affect our business, results of operations, cash flows and financial condition.

	•	Environmental costs and liabilities and changing environmental regulation could materially affect our results of operations, cash flows and financial condition.

	•	We depend on Enterprise Products Partners and certain other key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash from operations available to pay distributions to you.

	•	Because of the natural decline in gas production from existing wells, our success depends on our ability to obtain access to new sources of natural gas, which is dependent on factors beyond our control. Any decrease in supplies of natural gas could adversely affect our business and operating results.

	•	Successful development of LNG import terminals outside our areas of operation could reduce the demand for our services.

	•	We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

Risks Inherent in an Investment in Us


	•	Affiliates of our general partner, including Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners, may compete with us, and business opportunities may be directed by contract to Enterprise Products Partners and Enterprise GP Holdings before us under the administrative services agreement.

	•	Our general partner and its affiliates, including Enterprise Products Partners, will own a controlling interest in us and have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.

	•	Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

	•	Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.


	•	An affiliate of our general partner will have the power to appoint and remove our directors and management. Unitholders have limited voting rights and are not entitled to elect our general partner or its directors, which could lower the trading price of our common units.

	•	You will experience immediate and substantial dilution of $6.68 per common unit.

	•	We may issue additional units without your approval, which would dilute your ownership interests.

	•	Cost reimbursements to EPCO and its affiliates will reduce cash available for distribution to you.

Tax Risks


	•	Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or the IRS, were to treat us as a corporation or if we were to become subject to entity-level taxation for state tax purposes, then our cash distributions to you would be substantially reduced.

	•	If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted, and the costs of any contest will reduce our cash distributions to you.

	•	You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Summary Historical and Pro Forma Financial and Operating Data

Duncan Energy Partners L.P. was formed on September 29, 2006; therefore, it does not have any historical financial statements prior to its formation. The following tables set forth, for the periods and at the dates indicated, the summary historical combined financial and operating data of Duncan Energy Partners Predecessor, which was derived from the books and records of Enterprise Products Partners.

The summary historical combined financial data for the years ended December 31, 2005, 2004 and 2003 and combined balance sheet data at December 31, 2005 and 2004 is derived from and should be read in conjunction with the audited combined financial statements of Duncan Energy Partners Predecessor included elsewhere in this prospectus beginning on page F-13. The summary historical combined financial and operating data for the six months ended June 30, 2006 and 2005 and combined balance sheet at June 30, 2006 is derived from and should be read in conjunction with the unaudited condensed combined financial statements of Duncan Energy Partners Predecessor included elsewhere in this prospectus beginning on page F-42. The operating data for all periods are unaudited. The summary unaudited pro forma combined financial data of Duncan Energy Partners was derived from and should be read in conjunction with our unaudited pro forma condensed combined financial statements included in this prospectus beginning on page F-2. The following information should also be read together with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Enterprise Products Partners, through its subsidiaries, has owned controlling interests and operated the underlying assets of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene for several years. Enterprise Products Partners will retain a 34% ownership interest in each of these four entities (as well as South Texas NGL). Enterprise Products Partners will own our general partner, DEP Holdings, which owns a 2% general partner interest in us, and therefore indirectly has the ability to control us. In addition, Enterprise Products Partners will own approximately 36.0% of our common units after completion of this offering, or approximately 26.3% of our outstanding common units if the underwriters exercise their option to purchase additional common units in full. For financial reporting purposes, the ownership interests of Enterprise Products Partners are deemed to represent the parent (or sponsor) interest in our pro forma results of our operations and financial position.

The summary unaudited pro forma combined financial data for the six months ended June 30, 2006 and for the year ended December 31, 2005 assume the pro forma transactions noted herein occurred at the beginning of each period presented or on June 30, 2006 for the balance sheet data. These transactions include:


	•	The August 2006 purchase of a pipeline by Enterprise Products Partners for approximately $97.7 million in cash, the subsequent contribution of this pipeline to South Texas NGL, and estimated additional costs of $37.7 million required to modify this pipeline and to acquire and construct additional pipelines in order to place this system into operation in January 2007. The pro forma financial data does not reflect estimated additional capital expenditures of $30.9 million that will be made by South Texas NGL in 2007 to complete planned expansions to this system. We will retain cash in an amount equal to our 66% share (approximately $20.4 million) of these estimated capital expenditures from the net proceeds of this offering in order to fund our share of the planned expansion costs. The pro forma combined results of operations data does not reflect any results attributable to the historical activities of this pipeline.

	•	The contribution of a 66% interest in certain entities, which are wholly-owned subsidiaries of Enterprise Products Partners, and the retention by Enterprise Products Partners of a 34% interest in these entities.

	•	The revision of related party storage contracts between us and Enterprise Products Partners to (1) increase certain storage fees paid by Enterprise Products Partners and (2) reflect the allocation to Enterprise Products Partners of all storage measurement gains and losses relating to products under these agreements, and the execution of a limited liability company agreement for Mont Belvieu Caverns providing for the special allocation and other agreements relating to other measurement gains and losses to Enterprise Products Partners.


	•	The assignment to us of certain third-party agreements that effectively reduce tariff rates received by us for the transport of propylene volumes.

Our unaudited pro forma, as adjusted financial data also gives effect to the following:


	•	our borrowing of $200 million under a new bank credit facility;

	•	our issuance and sale of 13,000,000 common units to the public in this offering;

	•	our payment of estimated underwriting discounts and commissions, a structuring fee and other offering expenses; and

	•	our use of net proceeds from the borrowing and this offering as consideration for the contributed ownership interests in Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL from Enterprise Products Partners.

The following table presents the summary historical combined financial and operating data of Duncan Energy Partners Predecessor and our summary unaudited pro forma combined financial information for the annual periods indicated (dollars in thousands, except per unit amounts):


									Duncan Energy Partners L.P.
									For the Year Ended
	Duncan Energy Partners Predecessor								December 31, 2005
	For the Year Ended December 31,								Pro			Pro Forma
	2003		2004			2005			Forma			As Adjusted

Combined Results of Operations Data:(1)
Revenues	$	668,234	$	748,931		$	953,397		$	946,568		$	946,568
Costs and expenses:
Operating costs and expenses		609,774		685,544			909,044			905,989			905,989
General and administrative expenses		6,138		5,442			4,483			6,983			6,983

Total costs and expenses		615,912		690,986			913,527			912,972			912,972

Equity in income of unconsolidated affiliates		131		231			331			331			331

Operating income		52,453		58,176			40,201			33,927			33,927

Interest expense							(532	)		(532	)		(13,932	)
Other income (expense), net		1		(52	)

Total other income (expense)		1		(52	)		(532	)		(532	)		(13,932	)

Income before parent interest		52,454		58,124			39,669			33,395			19,995
Parent’s share of income													(14,226	)

Income from continuing operations		52,454		58,124			39,669		$	33,395		$	5,769

Cumulative effect of change in accounting principle							(582	)

Net income	$	52,454	$	58,124		$	39,087

Earnings per unit — public, basic and diluted												$	0.44

Combined Balance Sheet Data (at period end):(1)
Total assets	$	581,816	$	590,487		$	642,840
Owners’ net investment		524,127		509,719			527,767
Other Combined Financial Data:(1)
Net cash flows provided by operating activities	$	64,732	$	79,463		$	40,568
Cash flows used in investing activities		340		6,931			19,503
Cash flows used in (provided by) financing activities (2)		64,392		72,532			21,065
Gross operating margin		76,473		81,985			64,142		$	60,368		$	60,368
EBITDA		70,336		76,498			59,072			53,380			39,154
Operating Data:(1)
Natural Gas Pipelines & Services, net:
Natural gas throughput volumes (Bbtus/d)		600		645			640			640			640
Petrochemical Pipeline Services, net:
Petrochemical transportation volumes (MBbls/d)		40		39			33			33			33

The following table presents the summary historical combined financial and operating data of Duncan Energy Partners Predecessor and our summary unaudited pro forma combined financial information for the interim periods indicated (dollars in thousands, except per unit amounts):


	Duncan Energy					Duncan Energy Partners L.P.
	Partners Predecessor					For the Six Months
	For the Six Months					Ended June 30, 2006
	Ended June 30,					Pro			Pro Forma
	2005		2006			Forma			As Adjusted

Combined Results of Operations Data:(1)
Revenues	$	400,029	$	503,791		$	499,210		$	499,210
Costs and expenses:
Operating costs and expenses		377,779		478,586			478,309			478,309
General and administrative expenses		2,436		1,735			2,985			2,985

Total costs and expenses		380,215		480,321			481,294			481,294

Equity in income of unconsolidated affiliates		197		354			354			354

Operating income		20,011		23,824			18,270			18,270

Interest expense										(6,647	)
Other income (expense), net				4			4			4

Total other income (expense)				4			4			(6,643	)

Income before provision for income taxes and parent interest		20,011		23,828			18,274			11,627
Provision for income taxes				(21	)		(21	)		(21	)

Income before parent interest		20,011		23,807			18,253			11,606
Parent’s share of net income										(7,895	)

Income from continuing operations		20,011		23,807		$	18,253		$	3,711

Cumulative effect of change in accounting principle				9

Net income	$	20,011	$	23,816

Earnings per unit — public, basic and diluted									$	0.29

Combined Balance Sheet Data (at period end):(1)
Total assets	$	590,060	$	626,721		$	762,089		$	784,483
Total debt										200,000
Parent’s interest in the Partnership										275,080
Owners’ net investment		515,465		557,934			694,106
Partners’ equity — public										241,420
Other Combined Financial Data:(1)
Net cash flows provided by operating activities	$	23,676	$	26,876
Cash flows used in investing activities		9,409		33,227
Cash flows used in (provided by) financing activities(2)		14,267		(6,351	)
Gross operating margin		31,878		35,695		$	31,391		$	31,391
EBITDA		29,443		33,986			28,423			20,528
Operating Data:(1)
Natural Gas Pipelines & Services, net:
Natural gas throughput volumes (Bbtus/d)		663		789			789			789
Petrochemical Pipeline Services, net:
Petrochemical transportation volumes (MBbls/d)		38		35			35			35

of these non-GAAP financial measures and reconciliations of these non-GAAP financial measures to their most directly comparable GAAP financial measures, please read “— Non-GAAP Financial Measures.”

The following information is provided to highlight significant trends and other information regarding Duncan Energy Partners Predecessor’s historical operating results, financial position and other financial data. Each section below represents a footnote to the tables above:

(1) We view the combined financial data of Duncan Energy Partners Predecessor from the financial statements of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene, which were derived from the accounts and records of Enterprise Products Partners. Enterprise Products Partners did not own certain of the businesses for all periods presented in this section. As a result, the summary selected data reflects the following information:


	•	Enterprise Products Partners owned Mont Belvieu Caverns and Lou-Tex Propylene for all periods presented.

	•	Enterprise Products Partners acquired Acadian Gas in April 2001; therefore, the selected data includes Acadian Gas from the date of its acquisition. No financial data was available from the seller for periods prior to April 2001.

	•	Enterprise Products Partners constructed the pipeline owned by Sabine Propylene and placed it in service in November 2001; therefore, the selected data includes Sabine Propylene from November 2001 to present.

	•	In August 2006, Enterprise Products Partners purchased a 223-mile pipeline extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The total purchase price for this asset was approximately $97.7 million in cash. This pipeline system will be owned by South Texas NGL (along with others being constructed and to be acquired) and will be used to transport NGLs from two Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas. The total estimated cost to acquire and construct the additional pipelines is $68.6 million. Our pro forma balance sheet data reflects assumed capital expenditures of $37.7 million, including approximately $8 million to purchase a 10-mile pipeline from TEPPCO Partners, to make this pipeline system operational prior to the closing of this offering. We expect that it will cost an additional $30.9 million to complete planned expansions of the South Texas NGL pipeline after the closing of this offering, of which our 66% share will be approximately $20.4 million. This expenditure is not reflected in the pro forma financial data because we expect to use cash on hand from the proceeds of this offering to fund this cost.

Duncan Energy Partners Predecessor’s historical financial information does not reflect any transactions related to the NGL pipeline asset acquired in August 2006 or subsequent capital expenditures for the construction and acquisition of related pipelines. Furthermore, the pro forma adjustments are limited to those required to present an estimate of owners’ net investment immediately prior to this offering. The pro forma income statements do not reflect any results of operations attributable to the historical activities of the existing NGL pipelines.

ExxonMobil has informed us that no discrete and separable financial information existed for the pipeline we acquired in August 2006, which was comprised of two separately operated pipelines prior to our purchase. The seller had previously utilized these pipelines for a different product and the pipeline was out of service when we acquired it. The 10-mile pipeline to be purchased from TEPPCO Partners was used as a feeder line for NGL products and operated by different management. We understand no financial statement information is available for this minor component asset. There is no meaningful financial data available regarding the prior use of these pipelines by the sellers that would be meaningful to our investors. In addition, such data, if available, would not assist investors in understanding either the evolution of the business (which is a new NGL transportation network) nor the track record of management (which will be different).

by operations less cash used in investing activities. Conversely, cash flows provided by financing activities represent contributions from Enterprise Products Partners.

For additional information regarding our combined results of operations and liquidity and capital resources, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Non-GAAP Financial Measures

We include in this prospectus the non-GAAP financial measures of gross operating margin and EBITDA, and provide reconciliations of these non-GAAP measures to their most directly comparable measure or measures calculated and presented in accordance with GAAP.

Gross operating margin. We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (total and by 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 combined) segment gross operating margin as operating income before: (1) depreciation, amortization and accretion expense; (2) gains and losses on the sale of assets; and (3) 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 any intersegment and intrasegment transactions. Our combined revenues reflect the elimination of all material intercompany transactions.

We include equity earnings from Evangeline, a subsidiary of Acadian Gas, in our measurement of the Natural Gas Pipelines & Services segment gross operating margin and operating income. Our equity investments in midstream energy operations such as those conducted by Evangeline are a vital component of our long-term business strategy and important to the operations of Acadian Gas. This method of operation enables us to achieve favorable economies of scale relative to our level of investment and also lowers our exposure to business risks compared the profile we would have on a stand-alone basis. Our equity investments are within the same industry as our combined operations; therefore, we believe treatment of earnings from our equity method investee as a component of gross operating margin and operating income is appropriate.

EBITDA. We define EBITDA as net income or loss plus interest expense, provision for income taxes and depreciation, accretion and amortization expense. EBITDA is commonly used as a supplemental financial measure by management and by external users of our financial statements, such as investors, commercial banks, research analysts and rating agencies, to assess: (1) the financial performance of our assets without regard to financing methods, capital structures or historical cost basis; (2) the ability of our assets to generate cash sufficient to pay interest cost and support our indebtedness; (3) our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and (4) the viability of projects and the overall rates of return on alternative investment opportunities. Because EBITDA excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the EBITDA data presented in this prospectus may not be comparable to similarly titled measures of other companies. The GAAP measure most directly comparable to EBITDA is net cash provided by operating activities.

The following tables present (1) a reconciliation of the non-GAAP financial measure of gross operating margin to the GAAP financial measure of operating income and (2) a reconciliation of the non-GAAP financial measure of EBITDA to the GAAP financial measure of net income (income from continuing operations with regards to our pro forma information) on a historical and pro forma basis, as applicable, for each of the periods presented (dollars in thousands). With regards to EBITDA measures determined using the historical financial information of Duncan Energy Partners Predecessor, EBITDA is also reconciled to the GAAP financial measure of net cash provided by operating activities.


										Duncan Energy Partners L.P.
										For the Year Ended
										December 31, 2005
	Duncan Energy Partners Predecessor											Pro Forma
	For the Year Ended December 31,									Pro		As
	2003			2004			2005			Forma		Adjusted

Reconciliation of GAAP “operating income” to non-GAAP “gross operating margin”
Operating income	$	52,453		$	58,176		$	40,201		$	33,927	$	33,927
Adjustments to reconcile operating income to gross operating margin:
Depreciation, amortization and accretion in operating costs and expenses		17,882			18,374			19,453			19,453		19,453
Loss (gain) on sale of assets in operating costs and expenses					(7	)		5			5		5
General and administrative costs		6,138			5,442			4,483			6,983		6,983

Total gross operating margin	$	76,473		$	81,985		$	64,142		$	60,368	$	60,368

Reconciliation of non-GAAP “EBITDA” to GAAP “net income” (or GAAP “income from continuing operations” with respect to pro forma data) and GAAP “net cash provided by operating activities”
Net income (income from continuing operations with respect to pro forma data)	$	52,454		$	58,124		$	39,087		$	33,395	$	5,769
Additions to income to derive EBITDA:
Interest expense								532			532		13,932
Depreciation, accretion and amortization		17,882			18,374			19,453			19,453		19,453

EBITDA	$	70,336		$	76,498		$	59,072		$	53,380	$	39,154

Adjustments to EBITDA to derive net cash provided by operating activities (add or subtract as indicated by sign of number):
Cumulative effect of change in accounting principle								582
Interest expense								(532	)
Equity in income of unconsolidated affiliates		(131	)		(231	)		(331	)
Loss (gain) on sale of assets					(7	)		5
Changes in fair market value of financial instruments		2			5			52
Net effect of changes in operating accounts		(5,475	)		3,198			(18,280	)

Net cash provided by operating activities	$	64,732		$	79,463		$	40,568


							Duncan Energy Partners L.P.
							For the Six Months
	Duncan Energy						Ended June 30, 2006
	Partners Predecessor									Pro
	For the Six Months									Forma
	Ended June 30,						Pro			As
	2005			2006			Forma			Adjusted

Reconciliation of GAAP “operating income” to non-GAAP “gross operating margin”
Operating income	$	20,011		$	23,824		$	18,270		$	18,270
Adjustments to reconcile operating income to gross operating margin:
Depreciation, amortization and accretion in operating costs and expenses		9,432			10,149			10,149			10,149
Gain on sale of assets in operating costs and expenses		(1	)		(13	)		(13	)		(13	)
General and administrative costs		2,436			1,735			2,985			2,985

Total gross operating margin	$	31,878		$	35,695		$	31,391		$	31,391

Reconciliation of non-GAAP “EBITDA” to GAAP “net income” (or GAAP “income from continuing operations” with respect to pro forma data) and GAAP “net cash provided by operating activities”
Net income (income from continuing operations with respect to pro forma data)	$	20,011		$	23,816		$	18,253		$	3,711
Additions to income to derive EBITDA:
Interest expense											6,647
Provision for income taxes					21			21			21
Depreciation, accretion and amortization		9,432			10,149			10,149			10,149

EBITDA	$	29,443		$	33,986		$	28,423		$	20,528

Adjustments to EBITDA to derive net cash provided by operating activities (add or subtract as indicated by sign of number):
Provision for income taxes					(21	)
Cumulative effect of change in accounting principle					(9	)
Equity in income of unconsolidated affiliates		(197	)		(354	)
Deferred income tax expense					21
Gain on sale of assets		(1	)		(13	)
Changes in fair market value of financial instruments		3			(53	)
Net effect of changes in operating accounts		(5,572	)		(6,681	)

Net cash provided by operating activities	$	23,676		$	26,876

RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, our business, financial condition, or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Inherent in Our Business

We may not have sufficient available cash to enable us to pay our expected initial quarterly distribution on our common units after establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to our general partner.

We may not have sufficient available cash each quarter to pay our expected initial quarterly distribution. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:


	•	the effects of competition on the rates we may charge for our transportation and storage services and the volumes of natural gas, NGLs and propylene our customers transport or store;

	•	the overall demand for natural gas, propylene and NGLs in the markets we serve and the quantities of natural gas, NGLs and propylene available for transport;

	•	competition from alternative fuels;

	•	regulatory action affecting the demand for natural gas, the supply of natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs or operating flexibility;

	•	weather conditions impacting the consumption of natural gas and weather-related and other natural disasters damaging our facilities and those of our customers and suppliers;

	•	force majeure or terrorist acts which could interrupt or otherwise adversely impact our operations and costs;

	•	regulatory and economic limitations on the development of LNG import terminals in the Gulf Coast region;

	•	successful development of LNG import terminals outside our areas of operation, which could reduce the need for gas transported on our pipeline systems;

	•	difficulties in collecting our receivables (including loaned gas) because of credit or financial problems of major customers;

	•	the level of our operating costs, including reimbursement of expenses to our general partner; and

	•	prevailing economic and market conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors such as:


	•	the level of our capital expenditures;

	•	the restrictions on distributions contained in our credit agreement and our debt service requirements;

	•	the cost of acquisitions, if any;

	•	fluctuations in our working capital needs;


	•	our ability to borrow to make distributions to our unitholders; and

	•	the amount, if any, of cash reserves established by our general partner.


	On a pro forma historical basis, we would not have had sufficient cash available for distributions to pay the expected initial quarterly distribution on all common units for the year ended December 31, 2005 and the four quarters ended June 30, 2006.

The amount of available cash we will need to pay our expected initial quarterly distribution for four quarters on the common units and the 2% general partner interest to be outstanding immediately after this offering is approximately $33.1 million. Pro forma combined available cash to make distributions generated during 2005 and the twelve months ended June 30, 2006 would have been approximately $9.9 million and a deficit of $2.8 million, respectively. These amounts would have been sufficient to allow us to pay only 30% of the initial quarterly distributions on the common units and the 2% general partner interest during 2005. These amounts would not have been sufficient to allow us to pay any distributions on our common units and the general partner interest during the four quarters ended June 30, 2006. For a calculation of our ability to make distributions to unitholders based on our pro forma results in 2005 and for the twelve months ended June 30, 2006, as well as estimated cash available to pay distributions for the four quarters ending December 31, 2007, please read “Cash Distribution Policy and Restrictions on Distributions.”


	The assumptions underlying our estimate of cash available for distribution we include in our “Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those expected.

Our estimate of cash available for distribution set forth in “Cash Distribution Policy and Restrictions on Distributions” is based on assumptions that are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. Furthermore, our estimate of cash available for distribution for the four quarters ending December 31, 2007 is equal to the amount of available cash we need to pay the expected initial quarterly distribution on all common units for such quarters. If we do not achieve the estimated results, we may not be able to pay the full expected initial quarterly distribution or any amount on our common units, in which event the market price of our common units may decline materially.


	*The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.*

The amount of cash we have available for distribution depends primarily on our cash flow, including cash flow from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.


	*Changes in demand for and production of hydrocarbon products may materially adversely affect our results of operations, cash flows and financial condition.*

We operate predominantly in the midstream energy sector which includes transporting and storing natural gas, NGLs and propylene. As such, our results of operations, cash flows and financial condition may be materially adversely affected by changes in the prices of these hydrocarbon products and by changes in the relative price levels among these hydrocarbon products. Changes in prices and changes in the relative price levels may impact demand for hydrocarbon products, which in turn may impact production and volumes transported by us and related transportation and storage handling fees. We may also incur price risk to the extent counterparties do not perform in connection with our marketing of natural gas, NGLs and propylene.

In the past, the prices of natural gas have been extremely volatile, and we expect this volatility to continue. The NYMEX daily settlement price for natural gas for the prompt month contract in 2004 ranged from a high of $8.75 per MMBtu to a low of $4.57 per MMBtu. In 2005, the same index ranged from a high

of $15.38 per MMBtu to a low of $5.79 per MMBtu. In the first nine months of 2006, the same index ranged from a high of $10.63 per MMBtu to a low of $4.20 per MMBtu.

Generally, the prices of natural gas, NGLs and other hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors that are impossible to control. These factors include:


	•	the level of domestic production and consumer product demand;

	•	the availability of imported natural gas;

	•	actions taken by foreign natural gas producing nations;

	•	the availability of transportation systems with adequate capacity;

	•	the availability of competitive fuels;

	•	fluctuating and seasonal demand for natural gas and NGLs;

	•	the impact of conservation efforts;

	•	the extent of governmental regulation and taxation of production; and

	•	the overall economic environment.


	A decrease in demand for natural gas, NGLs, NGL products or petrochemical products by the petrochemical, refining or heating industries could materially adversely affect our results of operations, cash flows and financial position.

A decrease in demand for natural gas, NGLs, NGL products or petrochemical products by the petrochemical, refining or heating industries, whether because of a general downturn in economic conditions, reduced demand by consumers for the end products made with products we transport, increased competition from petroleum-based products due to pricing differences, adverse weather conditions, increased government regulations affecting prices and production levels of natural gas or other reasons, could materially adversely affect our results of operations, cash flows and financial position. For example:


	•	Ethane. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. If natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls (and, therefore, the demand for ethane by NGL producers falls), it may be more profitable for natural gas producers to leave the ethane in the natural gas stream to be burned as fuel than to extract the ethane from the mixed NGL stream for sale as an ethylene feedstock.

	•	Propylene. Propylene is sold to petrochemical companies for a variety of uses, principally for the production of polypropylene. Propylene is subject to rapid and material price fluctuations. Any downturn in the domestic or international economy could cause reduced demand for, and an oversupply of propylene, which could cause a reduction in the volumes of propylene that we transport.


	Any decrease in supplies of natural gas could adversely affect our business and operating results. Because of the natural decline in gas production from existing wells, our success depends on our ability to obtain access to new sources of natural gas, which is dependent on factors beyond our control.

Over the past two years that have been reported, gas production from state waters of the Gulf Coast region, which supplies much of our throughput, has declined an average of approximately 2.9% from 133 Bcf for 2003 to 129 Bcf for 2004, according to the Energy Information Administration, or EIA. We cannot give any assurance regarding the gas production industry’s ability to find new sources of domestic supply. Production from existing wells and gas supply basins connected to our pipelines will naturally decline over time, which means that our cash flows associated with the gathering or transportation of gas from these wells and basins will also decline over time. The amount of natural gas reserves underlying these wells may also be less than we anticipate, and the rate at which production from these reserves declines may be greater than we

anticipate. Accordingly, to maintain or increase throughput levels on our pipelines, we must continually obtain access to new supplies of natural gas. The primary factors affecting our ability to obtain new sources of natural gas to our pipelines include:


	•	the level of successful drilling activity near our pipelines;

	•	our ability to compete for these supplies;

	•	our ability to connect our pipelines to the suppliers;

	•	the successful completion of new LNG facilities near our pipelines; and

	•	our gas quality requirements.

The level of drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is the price of oil and natural gas. These commodity prices reached record levels during 2006, but current prices have declined in recent months. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our pipelines, which would lead to reduced throughput levels on our pipelines. Other factors that impact production decisions include producers’ capital budget limitations, the ability of producers to obtain necessary drilling and other governmental permits, the availability and cost of drilling rigs and other drilling equipment, and regulatory changes. Because of these factors, even if new natural gas reserves were discovered in areas served by our pipelines, producers may choose not to develop those reserves or may connect them to different pipelines.

Imported LNG is expected to be a significant component of future natural gas supply to the United States. Much of this increase in LNG supplies is expected to be imported through new LNG facilities to be developed over the next decade. Eleven LNG projects have been approved by the FERC to be constructed in the Gulf Coast region and an additional four LNG projects have been proposed for the region. We cannot predict which, if any, of these projects will be constructed. If a significant number of these new projects fail to be developed with their announced capacity, or there are significant delays in such development, or if they are built in locations where they are not connected to our systems or they do not influence sources of supply on our systems, we may not realize expected increases in future natural gas supply available for transportation through our systems.

If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing supply basins, or if the expected increase in natural gas supply through imported LNG is not realized, throughput on our pipelines would decline which could have a material adverse effect on our financial condition, results of operations and ability to make distributions to you.

In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves dedicated to our pipeline systems. Accordingly, volumes of natural gas gathered on our pipeline systems in the future could be less than we anticipate, which could adversely affect our cash flow and our ability to make cash distributions to unitholders.

In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves connected to our pipeline systems due to the unwillingness of producers to provide reserve information as well as the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems (or to processing facilities such as those serving Enterprise Products Partners in South Texas) or the anticipated lives of such reserves. If the total reserves or estimated lives of the reserves connected to our pipeline systems, particularly in South Texas, is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas gathered on our pipeline systems in the future could be less than we anticipate. A decline in the volumes of natural gas gathered on our pipeline systems could have an adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to you.


	*We face competition from third parties and increased competition could have a significant financial impact on us.*

We compete primarily with other interstate and intrastate pipelines in the transportation and storage of natural gas, propylene and NGL products. Natural gas also competes with other forms of energy available to our customers, including electricity, coal and fuel oils. Even if reserves exist in the areas accessed by our facilities and are ultimately produced, we may not be chosen by the producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons that are produced. The principal elements of competition among our pipelines are geographic proximity to gas production or supplies, costs of connection, available capacity, rates, access to markets and reliability.

We also face competition from, and may be limited in our ability to pursue business opportunities also sought by, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners. Please read “— Risks Inherent in an Investment in Us — Enterprise Products Partners, EPCO and their affiliates may engage in competition with us, and business opportunities may be directed by contract to those affiliates prior to us under an amended and restated administrative services agreement.”

Increased competition could reduce the volumes of natural gas, propylene or NGLs transported by our pipeline systems or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative impact of factors that significantly decrease demand for natural gas in the markets served by our pipeline systems, such as competing or alternative forms of energy, a recession or other adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit their use. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions to you.


	*We will depend in large part on Enterprise Products Partners and the continued success of its business as we operate our assets as part of their value chain.*

We will enter into a number of material contracts with Enterprise Products Partners and its subsidiaries relating to transportation, storage and leases, and our cash flows and financial condition will depend in large part on the continued success of Enterprise Products Partners as we operate our assets as part of its value chain. For example, our South Texas NGL system revenues will depend solely on the volumes processed at the South Texas facilities owned by Enterprise Products Partners. Enterprise Products Partners has no obligation to produce any volumes at these facilities. If anticipated volumes are not processed by Enterprise Products Partners at these facilities, our estimated revenues on this system will be adversely affected.


	*The credit and risk profile of our general partner and its owners could adversely affect our credit ratings and profile.*

The credit and business risk profiles of a general partner or owners of a general partner may be factors in credit evaluations of a master limited partnership. This is because the general partner controls the business activities of the partnership, including its cash distribution policy and acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of our general partner and its owners, including the degree of their financial leverage and their dependence on cash flow from the partnership to service their indebtedness.

If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of the owners of our general partner, as credit rating agencies such as Standard & Poor’s and Moody’s may consider these entities’ leverage because of their ownership interest in and control of us, the strong operational links between them and their affiliates and us, and our reliance on Enterprise Products Partners for a substantial percentage of our revenue. Any such adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise money in the capital markets, which would impair our ability to grow our business and make distributions to unitholders.

Affiliates of Enterprise Products Partners, the indirect owner of our general partner, have significant indebtedness outstanding and are dependent principally on the cash distributions from their general partner and limited partner interests in Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners to service such indebtedness. Any distributions by Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners to such entities will be made only after satisfying their then current obligations to their creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect the separateness of us and our general partner from the entities that control our general partner, and other entities controlled by Dan L. Duncan, our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of Dan L. Duncan or the entities that control our general partner were viewed as substantially lower or more risky than ours.


	A natural disaster, catastrophe or other event could result in severe personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow and, accordingly, affect the market price of our common units.

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Pipelines may suffer inadvertent damage from construction, and farm and utility equipment. Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms and floods.

If one or more facilities that we own or that deliver natural gas or other products to us are damaged by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions and, accordingly, adversely affect the market price of our common units.

EPCO maintains insurance coverage on behalf of us, although insurance will not cover many types of interruptions that might occur. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. For example, changes in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for us to obtain certain types of coverage. As a result, EPCO may not be able to renew existing insurance policies on behalf of us or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.


	*Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.*

At the closing of this offering, we expect to have approximately $200 million of indebtedness outstanding under our credit agreement and the ability to borrow an additional $ under the credit agreement. Our significant level of indebtedness could have important consequences to us, including:


	•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

	•	covenants contained in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;


	•	we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operation, future business opportunities and distributions to unitholders; and

	•	our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisition, investments or capital expenditures, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.


	*We anticipate that our new credit facility will contain operating and financial restrictions that may limit our business and financing activities.*

The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, we anticipate that our new credit agreement will restrict or limit our ability to:


	•	make distributions if any default or event of default occurs;

	•	incur additional indebtedness or guarantee other indebtedness;

	•	grant liens or make certain negative pledges;

	•	make certain loans or investments;

	•	make any material change to the nature of our business, including consolidations, liquidations and dissolutions; or

	•	enter into a merger, consolidation, sale and leaseback transaction or sale of assets.

Our ability to comply with the covenants and restrictions contained in our credit agreement may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit agreement, a significant portion of our indebtedness may become immediately due and payable, and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments.


	*Restrictions in our new credit facility could limit our ability to make distributions upon the occurrence of certain events.*

Our payment of principal and interest on our debt will reduce cash available for distributions on our common units. Our new credit agreement will limit our ability to make distributions upon the occurrence of the following events, among others:


	•	failure to pay any principal, interest, fees, expenses or other amounts when due;

	•	failure of any representation or warranty to be true and correct in any material respect;

	•	failure to perform or otherwise comply with the covenants in the credit agreement;

	•	failure to pay any other material debt;

	•	a bankruptcy or insolvency event involving us, our general partner or any of our subsidiaries;


	•	the entry of, and failure to pay, one or more adverse judgments in excess of a specified amount against which enforcement proceedings are brought or that are not stayed pending appeal;

	•	a change in control of us;

	•	a judgment default or a default under any material agreement if such default could have a material adverse effect on us; and

	•	the occurrence of certain events with respect to employee benefit plans subject to ERISA.

Any subsequent refinancing of our current debt or any new debt could have similar or more restrictive provisions. For more information regarding our credit agreement, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — New Credit Facility.”


	*Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.*

In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. After giving effect to this offering and the borrowing of approximately $200 million under our new credit agreement, pro forma as of June 30, 2006, we would have approximately $200 million of consolidated debt, of which we expect all will be at variable interest rates. As a result, our results of operations, cash flows and financial condition, could be materially adversely affected by significant increases in interest rates.

An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our common units. Any such reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.


	*Our hedging activities may have a material adverse effect on our earnings, profitability, cash flows, including its ability to make distributions, and financial condition.*

We utilize derivative financial instruments related to the future price of natural gas and the future price of NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices. While our hedging activities are designed to reduce commodity price risk, we remain exposed to fluctuations in commodity prices to some extent. The extent of our commodity price exposure is related largely to the effectiveness and scope of our hedging activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual natural gas prices or NGLs prices that we realize in our operations. Furthermore, our hedges relate to only a portion of the volume of our expected sales and, as a result, we will continue to have direct commodity price exposure to the unhedged portion. Our actual future sales may be significantly higher or lower than estimated at the time we entered into derivative transactions for such period. If the actual amount is higher than estimated, we will have greater commodity price exposure than intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from the sale or purchase of the underlying physical commodity, resulting in a substantial diminution of liquidity.

As a result of these factors, our hedging activities may not be as effective as intended in reducing the volatility of our cash flows, which could adversely affect our ability to make distributions to unitholders. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging procedures may not be properly followed. We cannot assure you that the steps we take to monitor our derivative financial instruments will detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.


	*Our construction of new assets is subject to regulatory, environmental, political, legal and economic risks.*

Our South Texas pipeline system will not be placed into operation or generate cash flow until we complete construction of a pipeline connecting it to Mont Belvieu, Texas. While we anticipate that construction of this pipeline will be complete and operations will commence in early January 2007, we cannot be certain that this construction project will be finished and the pipeline placed in service before the completion of this offering. In addition, one of the connections between our South Texas pipeline and the Mont Belvieu facility will be a pipeline we will lease from TEPPCO Partners. The initial term of this lease will expire on July 31, 2007, and if we are unable to construct our planned replacement pipeline or extend the lease, the operations of our South Texas pipeline will be interrupted. We cannot assure you that any construction will not be delayed due to government permits, weather conditions or other factors beyond our control.

In addition, one of the ways we intend to grow our business is through the construction of new midstream energy assets. The construction of new assets involves numerous operational, regulatory, environmental, political and legal risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things, the following:


	•	we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits;

	•	we will not receive any material increases in revenues until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;

	•	we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize;

	•	since we are not engaged in the exploration for and development of natural gas reserves, we may not have access to third-party estimates of reserves in an area prior to our constructing facilities in the area. As a result, we may make construct facilities in an area where the reserves are materially lower than we anticipate;

	•	where we do rely on third-party estimates of reserves in making a decision to construct facilities, these estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating reserves; and

	•	we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical.

A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from expansion opportunities or construction projects.


	*We may be limited in our ability to make acquisitions or unable to make acquisitions on economically acceptable terms.*

We will be limited in our ability to make acquisitions by our business opportunity agreements with Enterprise Products Partners and Enterprise GP Holdings. These agreements will entitle them to take business opportunities for the benefit of themselves before allowing us to take them. In addition, our ability to grow depends, in part, on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions either because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to maintain and increase over time distributions will be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in our cash from operations per unit.

Any acquisition involves potential risks, including, among other things:


	•	mistaken assumptions about volumes, revenues and costs, including synergies;

	•	an inability to integrate successfully the businesses we acquire;

	•	a decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;

	•	a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition;

	•	the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

	•	an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;

	•	limitations on rights to indemnity from the seller;

	•	mistaken assumptions about the overall costs of equity or debt;

	•	the diversion of management’s and employees’ attention from other business concerns;

	•	unforeseen difficulties operating in new product areas or new geographic areas; and

	•	customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.


	*Federal, state or local regulatory measures could materially affect our business, results of operations, cash flow and financial condition.*

The Surface Transportation Board, or STB, regulates transportation on interstate propylene pipelines. The current version of the Interstate Commerce Act, or ICA, and its implementing regulations give the STB authority to regulate the rates we charge for service on the propylene pipelines and generally requires that our rates and practices be just and reasonable and nondiscriminatory. The rates we charge for movements on our propylene pipelines may be subject to challenge and any successful challenge to those rates could adversely affect our revenues. Our interstate propylene pipelines formerly were regulated by the FERC, and we cannot guarantee that the FERC will not reassert jurisdiction over those facilities in the future.

The intrastate natural gas pipeline transportation services we provide are subject to various Louisiana state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer. Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge. In addition, the transportation and storage services furnished by our intrastate natural gas facilities on behalf of interstate natural gas pipelines or certain local distribution companies are regulated by the FERC pursuant to Section 311 of the Natural Gas Policy Act of 1978, or NGPA. Pursuant to the NGPA, we are required to offer those services on an open and nondiscriminatory basis at a fair and equitable rate. Such FERC-regulated NGPA Section 311 rates also may be subject to challenge and successful challenges may adversely affect our revenues.

Although our natural gas gathering systems are generally exempt from FERC regulation under the Natural Gas Act of 1938, FERC regulation still significantly affects our natural gas gathering business. In recent years, the FERC has pursued pro-competition policies in its regulation of interstate natural gas pipelines. If the FERC does not continue this approach, it could have an adverse effect on the rates we are able to charge in the future. In addition, the distinction between FERC-regulated transmission service and federally unregulated gathering services is the subject of regular litigation, so, in such a circumstance, the classification and regulation of some of our gathering facilities may be subject to change based on future

determinations by the FERC and the courts. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures.

For a general overview of federal, state and local regulation applicable to our assets, please read “Business — Regulation of Operations.”

Our partnership status may be a disadvantage to us in calculating our cost of service for rate-making purposes.

In May 2005, the FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass-through partnership entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. The policy statement also provides that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. In August 2005, the FERC also dismissed requests for rehearing of its new policy statement. On December 16, 2005, the FERC issued its first significant case-specific review of the income tax allowance issue in another company’s rate case. The FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The new tax allowance policy and the December 16 order have been appealed to the United States Court of Appeals for the District of Columbia Circuit. As a result, the ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost of service. Depending upon how the policy statement on income tax allowances is applied in practice to pipelines organized as pass-through entities, and whether it is ultimately upheld or modified on judicial review, these decisions might adversely affect us.


	*Environmental costs and liabilities and changing environmental regulation could materially affect our results of operations, cash flows and financial condition.*

Our operations are subject to extensive federal, state and local regulatory requirements relating to environmental affairs, health and safety, waste management and chemical and petroleum products. These include, for example, (1) the federal Clean Air Act and comparable state laws and regulations that impose obligations related to air emissions, (2) the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the discharge of waste from our facilities and (3) the Comprehensive Environmental Response Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the clean up of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal. Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to administrative, civil and criminal penalties, including substantial fines, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental laws, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to cleanup and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

We will make expenditures in connection with environmental matters as part of normal capital expenditure programs. However, future environmental law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations, including the handling, manufacture, use, emission or disposal of substances and wastes.


	*Our pipeline integrity program may impose significant costs and liabilities on us.*

Pursuant to the Pipeline Safety Improvement Act of 2002, the United States Department of Transportation, or DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:


	•	perform ongoing assessments of pipeline integrity;

	•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

	•	improve data collection, integration and analysis;

	•	repair and remediate the pipeline, as necessary; and

	•	implement preventive and mitigating actions.

At this time, we cannot predict the ultimate costs of compliance with this rule because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing that is required by the rule. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.


	We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could adversely affect our ability to make distributions to you.

The workplaces associated with our pipelines are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities and local residents. The failure to comply with OSHA requirements or general industry standards, keep adequate records or monitor occupational exposure to regulated substances could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.


	We depend on Enterprise Products Partners and certain other key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to make distributions to you.

We rely on a limited number of customers for a significant portion of revenues. For the year ended December 31, 2005 and the six months ended June 30, 2006, Enterprise Products Partners and its affiliates accounted for approximately 9% and 11% of our total combined revenues, respectively. Several of our assets also rely on only one or two customers for the asset’s cash flow. For example, the only shipper on our South Texas NGL pipeline, which will be operational beginning in January 2007, will be Enterprise Products Partners; the only customers on our Lou-Tex pipeline are ExxonMobil and Shell; the only customer on our Sabine pipeline is Shell and the only shipper on the pipeline held by Evangeline is Entergy. In order for new customers to use these pipelines, we or the new shippers would be required to construct interim pipeline connections.

Our contracts with affiliates include storage leases between Mont Belvieu Caverns and certain subsidiaries of Enterprise Products Partners and TEPPCO Partners that will reflect amendments to prior agreements effective concurrently with the closing of this offering. The effect of these amendments will be to decrease the total fees payable to us. Although we believe the current agreements will generally reflect current market rates, these agreements will be entered into with affiliates and not through arms’ length negotiations. Please read “Certain Relationships and Related Party Transactions — Related Party Transactions with Enterprise Products Partners” for a description of our affiliate contracts.

We may be unable to negotiate extensions or replacements of these contracts and those with other key customers on favorable terms. The loss of all or even a portion of the contracted volumes of these customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our financial condition, results of operations and ability to make distributions to you, unless we are able to contract for comparable volumes from other customers at favorable rates.


	We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks. We generally do not require collateral for our accounts receivable. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness and any resulting increase in nonpayment or nonperformance by them could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.


	*We depend on the leadership and involvement of Dan L. Duncan and other key personnel for the success of our and our subsidiaries’ businesses.*

We depend on the leadership, involvement and services of Dan L. Duncan, the founder of EPCO and the Chairman of our general partner. Mr. Duncan has been integral to the success of Enterprise Products Partners and the success of EPCO, and will be integral to our success, due in part to his ability to identify and develop business opportunities, make strategic decisions and attract and retain key personnel. The loss of his leadership and involvement or the services of any members of our senior management team could have a material adverse effect on our business, results of operations, cash flows and financial condition.


	*Successful development of LNG import terminals outside our areas of operations could reduce the demand for our services.*

Development of new, or expansion of existing, LNG facilities outside our areas of operations could reduce the need for customers to transport natural gas from supply basins connected to our pipelines. This could reduce the amount of gas transported by our pipelines for delivery off-system to other intrastate or interstate pipelines serving these customers. If we are not able to replace these volumes with volumes to other markets or other regions, throughput on our pipelines would decline which could have a material adverse effect on our financial condition, results of operations and ability to make distributions to you.


	*We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.*

We do not own all of the land on which our pipelines and facilities are located, and we are therefore subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, or increased costs to renew such rights, could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions to you.


	*Mergers among our customers or competitors could result in lower volumes being shipped on our pipelines, thereby reducing the amount of cash we generate.*

Mergers among our existing customers or competitors could provide strong economic incentives for the combined entities to utilize systems other than ours and we could experience difficulty in replacing lost volumes and revenues. Because most of our operating costs are fixed, a reduction in volumes would result in

not only a reduction of revenues, but also a decline in net income and cash flow of a similar magnitude, which would reduce our ability to meet our financial obligations and make distributions to you.


	*Because of our lack of asset and geographic diversification, adverse developments in our pipeline operations would reduce our ability to make distributions to our unitholders.*

We rely on the revenues generated from our pipelines and related assets. Furthermore, our assets are concentrated in Texas and Louisiana. Due to our lack of diversification in asset type and location, an adverse development in our business or our operating areas would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.


	*Terrorist attacks aimed at our facilities could adversely affect our business, results of operations, cash flows and financial condition.*

Since the September 11, 2001 terrorist attacks on the United States, the United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations. Any terrorist attack on our facilities or pipelines or those of our customers could have a material adverse effect on our business.

Risks Inherent in an Investment in Us


	Enterprise Products Partners, EPCO and their affiliates may compete with us, and business opportunities may be directed by contract to those affiliates prior to us under the administrative services agreement.

Our partnership agreement will not prohibit Enterprise Products Partners, EPCO and their affiliates, other than our general partner, from owning and operating natural gas and NGL pipeline and storage assets or engaging in businesses that otherwise compete directly or indirectly with us. In addition, Enterprise Products Partners and EPCO may acquire, construct or dispose of additional midstream or other natural gas assets in the future, without any obligation to offer us the opportunity to purchase or construct any of these assets.

Under the administrative services agreement that we will enter into prior to the closing of this offering, if any business opportunity, other than a business opportunity to acquire general partner interests and other related equity securities in a publicly traded partnership, is presented to EPCO and its affiliates, us and our general partner, Enterprise Products Partners and its general partner, or Enterprise GP Holdings and its general partner, then Enterprise Products Partners will have the first right to pursue such opportunity for itself or, in its sole discretion, to affirmatively direct the opportunity to us. If Enterprise Products Partners abandons the business opportunity for itself or for us, then Enterprise GP Holdings will have the second right to pursue such opportunity. If any business opportunity to acquire general partner interests and other related equity securities in a publicly traded partnership is presented, then Enterprise GP Holdings will have the right to pursue such opportunity before Enterprise Products Partners is given the opportunity to pursue it for itself or to direct it to us. Accordingly, we will be limited by contract in our ability to take certain business opportunities for our partnership. Please read “Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties.”


	Our general partner and its affiliates own a controlling interest in us and have conflicts of interest and limited fiduciary duties, which may permit them to favor their own interests to your detriment.

Following the offering, Enterprise Products OLP will own indirectly a 2% general partner interest and directly approximately 36.0% of our outstanding common units (or approximately 26.3% of our outstanding common units if the underwriters’ option to purchase additional common units is exercised in full) and will own and control our general partner, which controls us. Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage it and our general partner in a manner beneficial to Enterprise Products Partners and its affiliates. Furthermore, certain directors and officers of our general partner may be directors or officers of affiliates of our general partner. Conflicts of interest may arise between Enterprise Products Partners and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of

its affiliates over the interests of our unitholders. Please read “— Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.” These potential conflicts include, among others, the following situations:


	•	Enterprise Products Partners, EPCO and their affiliates may engage in substantial competition with us on the terms set forth in an amended and restated administrative services agreement. Please read “— Enterprise Products Partners, EPCO and their affiliates may engage in competition with us, and business opportunities may be directed by contract to those affiliates prior to us under an amended and restated administrative services agreement.”

	•	Neither our partnership agreement nor any other agreement requires EPCO, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners or their affiliates (other than our general partner) to pursue a business strategy that favors us. Directors and officers of EPCO and the general partners of Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners and their affiliates have a fiduciary duty to make decisions in the best interest of their shareholders or unitholders, which may be contrary to our interests.

	•	Our general partner is allowed to take into account the interests of parties other than us, such as EPCO, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners and their affiliates, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

	•	Some of the officers of EPCO who provide services to us also may devote significant time to the business of Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners, and will be compensated by EPCO for such services.

	•	Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law.

	•	Our general partner determines the amount and timing of asset purchases and sales, operating expenditures, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders.

	•	Our general partner determines which costs, including allocated overhead, incurred by it and its affiliates are reimbursable by us.

	•	Enterprise Products Partners or TEPPCO Partners may propose to contribute additional assets to us and, in making such proposal, the directors of those entities have a fiduciary duty to their unitholders and not to our unitholders.

	•	Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf, and provides that reimbursement to EPCO for amounts allocable to us consistent with accounting and allocation methodologies generally permitted by the FERC for rate-making purposes and past business practices is deemed fair and reasonable to us.

	•	Our general partner intends to limit its liability regarding our contractual obligations.

	•	Our general partner may exercise its rights to call and purchase all of our common units if at any time it and its affiliates own more than 80% of the outstanding common units.


	•	Our general partner controls the enforcement of obligations owed to us by it and its affiliates, including the administrative services agreement.

	•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Please read “Certain Relationships and Related Party Transactions” and “Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties.”


	*We may be limited in our ability to consummate transactions, including acquisitions with affiliates of our general partner.*

We will have inherent conflicts of interest with affiliates of our general partner, including Enterprise Products Partners and TEPPCO Partners. These conflicts may cause the Audit and Conflicts Committees of these entities not to approve, or unitholders of these entities to dispute, any transactions that may be proposed or consummated between or among us and these affiliates. This may inhibit or prevent us from consummating transactions, including acquisitions, with them.


	*We do not have any officers or employees and rely solely on officers of our general partner and employees of EPCO and its affiliates.*

Certain of the executive officers and directors of our general partner are also officers and/or directors of EPCO, the general partner of Enterprise GP Holdings, the general partner of Enterprise Products Partners, the general partner of TEPPCO or other affiliates of EPCO. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our unitholders’ best interests. In addition, these overlapping executive officers and directors allocate their time among EPCO, Enterprise GP Holdings, Enterprise Products Partners, TEPPCO Partners, us and other affiliates of EPCO. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.


	*An affiliate of Enterprise Products Partners will have the power to appoint and remove our directors and management.*

Because Enterprise Products OLP owns 100% of DEP Holdings, it will have the ability to elect all the members of the board of directors of our general partner. Our general partner will have control over all decisions related to our operations. Furthermore, the goals and objectives of Enterprise Products OLP relating to us may not be consistent with those of a majority of the public unitholders.


	*Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.*

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of:


	•	the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and

	•	the highest price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed.

As a result, you may be required to sell your common units at a price that is less than the initial offering price in this offering or, because of the manner in which the purchase price is determined, at a price less than the then current market price of the common units. In addition, this call right may be exercised at an otherwise undesirable time or price and you may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. Our general partner is not obligated to obtain a fairness

opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units or other equity securities and exercising its call right. If our general partner exercised its call right, the effect would be to take us private and, if the common units were subsequently deregistered, we might no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act). Following this offering, affiliates of our general partner will own approximately 36.0% of the outstanding common units (approximately 26.3% of the outstanding common units if the underwriters exercise their option to purchase additional common units in full).

For additional information about the call right, please read “Description of Material Provisions of Our Partnership Agreement — Limited Call Right.”


	Our partnership agreement limits our general partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:


	•	permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Decisions made by our general partner in its individual capacity will be made by a majority of the owners of our general partner, and not by the board of directors of our general partner. Examples include the exercise of its limited call right, its rights to vote or transfer the common units it owns, its registration rights and the determination of whether to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

	•	provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the partnership;

	•	generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

	•	provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption; and

	•	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above. Please read “Description of Our Common Units — Transfer of Units.”


	*Unitholders have limited voting rights and are not entitled to elect our general partner or its directors, which could lower the trading price of our common units.*

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, is chosen entirely by its owners and not by the unitholders. Furthermore, even if our unitholders were dissatisfied with the performance of our general partner, they will, practically speaking, have no ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a control premium in the trading price.

The vote of the holders of at least 662/3% of all outstanding common units is required to remove our general partner. Following the closing of this offering, Enterprise Products Partners and its affiliates will own approximately 36.0% of our outstanding common units (or approximately 26.3% of our outstanding common units if the underwriters exercise their option to purchase additional common units in full).


	*Absent the consent of our general partner, our operations are limited to our current line of business, which could prevent us from diversifying our assets and our operations.*

Our partnership agreement will limit our business to the ownership and operation of natural gas pipelines and storage facilities and all other activities now and in the future customarily conducted in connection with that business. As a result, if our current business declines or if for any other reason we want to change or diversify our business, we will likely be unable to do so without the approval of our general partner, acting in its individual capacity. This could result in a decline in our business operations and a reduction in our ability to make distributions to you.


	*You will experience immediate and substantial dilution of $6.68 per unit.*

The assumed initial public offering price of $20.00 per unit exceeds the pro forma net tangible book value of $13.32 per common unit. Based on this assumed initial public offering price, you will incur immediate and substantial dilution of $6.68 per unit. This dilution results primarily because the assets sold and contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with GAAP. Please read “Dilution.”


	*We may issue additional units without your approval, which would dilute your ownership interests.*

At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. Our partnership agreement does not give our unitholders the right to approve our issuance of equity securities ranking junior to the common units at any time. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

The issuance by us of additional common units or other equity securities will have the following effects:


	•	the ownership interest of unitholders immediately prior to the issuance will decrease;

	•	the amount of cash distributions on each common unit may decrease;

	•	the relative voting strength of each previously outstanding common unit may be diminished;

	•	the ratio of taxable income to distributions may increase; and

	•	the market price of the common units may decline.


	*Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.*

Our partnership agreement restricts unitholders’ voting rights by providing that any common units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting common unitholders’ ability to influence the manner or direction of management.


	*We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets, which may affect our ability to make distributions to you.*

We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries and joint ventures. As a result, our ability to make distributions to our unitholders depends on the performance of our subsidiaries and joint ventures and their ability to distribute funds to us. The ability of our subsidiaries and joint ventures to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC policies. For example, all cash flows from Evangeline are currently used to service its debt.

Affiliates of Enterprise Products Partners currently own a minority equity interest in all of our subsidiaries and will have a right of first refusal to acquire these subsidiaries or their material assets if we desire to sell them, other than inventory and other assets sold in the ordinary course of business. These rights may adversely affect our ability to dispose of these assets. In addition, our ownership interest in Mont Belvieu Caverns may be diluted, and the cash flow from our NGL & Petrochemical Storage Services segment may be reduced, if we do not contribute our proportionate share of any future costs to fund expansion projects at Mont Belvieu Caverns.


	*We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.*

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our common units and other limited partner interests may decrease in direct correlation with decreases in the amount we distribute per common unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.


	*Cost reimbursements to EPCO and its affiliates will reduce cash available for distribution to you.*

Prior to making any distribution on the common units, we will reimburse EPCO and its affiliates for all expenses they incur on our behalf, including allocated overhead. These amounts will include all costs incurred in managing and operating us, including costs for rendering administrative staff and support services to us, and overhead allocated to us by EPCO. Please read “Cash Distribution Policy and Restrictions on Distributions,” “Certain Relationships and Related Party Transactions” and “Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties — Conflicts of Interest and Business Opportunity Agreements.” The payment of these amounts, including allocated overhead, to EPCO and its affiliates could adversely affect our ability to make distributions to you.


	*Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.*

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that:


	•	we were conducting business in a state, but had not complied with that particular state’s partnership statute; or

	•	your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business.

Please read “Description of Material Provisions of Our Partnership Agreement — Limited Liability” for a discussion of the implications of the limitations of liability on a unitholder.


	*Unitholders may have liability to repay distributions.*

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.


	*Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.*

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of DEP Holdings or Enterprise Products OLP to transfer their equity interests in our general partner or our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to influence the decisions taken by the board of directors and officers of our general partner.


	There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for the common units. After this offering, there will be 13,000,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units has been determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial

public offering price. The market price of our common units will also be influenced by many factors, some of which are beyond our control, including:


	•	our quarterly distributions;

	•	our quarterly or annual earnings or those of other companies in our industry;

	•	loss of a large customer;

	•	regulatory action on our rates or the services we provide;

	•	the adoption of new laws or regulations affecting us or adverse interpretation and application of existing laws or regulations affecting us;

	•	announcements by us or our competitors of significant expansion projects or acquisitions;

	•	changes in accounting standards, policies, guidance, interpretations or principles;

	•	general economic conditions;

	•	the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

	•	future sales of our common units; and

	•	the other factors described in these “Risk Factors.”

Tax Risks

You should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash distributions to you would be substantially reduced.

The anticipated after-tax benefit of an investment in the 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 IRS on this or any other matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of the common units.

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to a material amount of entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states, including Texas, are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we will be subject to a new entity-level state tax on the portion of our revenue that is generated in Texas beginning for tax reports due on or after January 1, 2008. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross revenue that is apportioned to Texas. If any additional state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced.


	If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted, and the costs of any contest will reduce our cash distributions to you.

We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from our counsel’s conclusions expressed in this prospectus. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, because the costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner, any such contest will result in a reduction in cash available for distribution.


	*You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.*

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.


	*Tax gain or loss on the disposition of our common units could be different than expected.*

If you sell your common units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price you receive is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to you.


	*Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.*

Investment in common units by tax-exempt entities, such as individual retirement accounts (“IRAs”), other retirement plans, and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person you should consult your tax advisor before investing in our common units.


	We will treat each purchaser of common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could result in a decrease in the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could decrease the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Tax Consequences — Uniformity of Units” for a further discussion of the effect of the depreciation and amortization positions we will adopt.


	*The sale or exchange of 50% or more of our capital and profits interests will result in the termination of our partnership for federal income tax purposes.*

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. Please read “Material Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.


	*You may be subject to state and local taxes and return filing requirements as a result of investing in our common units.*

In addition to federal income taxes, you will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. You may be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially conduct business in 12 states. We may own property or conduct business in other states or foreign countries in the future. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state and local tax consequences of an investment in our common units.

USE OF PROCEEDS

We expect to receive net proceeds from this offering of approximately $243.4 million (based on an assumed offering price of $20.00 per unit), after deducting the underwriting discount and a structuring fee, but before estimated expenses associated with the offering and related formation transactions.

We intend to use the net proceeds from this offering to:


	•	distribute approximately $221 million to Enterprise Products OLP as a portion of the cash consideration and reimbursement for capital expenditures relating to the assets contributed to us;

	•	provide approximately $20.4 million to fund our 66% share of estimated capital expenditures to complete planned expansions to the South Texas NGL pipeline subsequent to the closing of this offering; and

	•	pay $2 million of estimated net expenses associated with this offering and related formation transactions.

The portion of net proceeds that we retain to fund planned expansions (and the amount that we plan to distribute to Enterprise Products OLP) assumes that, prior to the closing date of this offering, South Texas NGL will have paid $37.7 million of a total estimated additional cost of $68.6 million to complete our acquisition and construction of the South Texas NGL pipeline system. The amounts actually distributed or retained at the closing of this offering will be increased or decreased by an amount equal to 66% of the difference between:

(1) $68.6 million (the estimated total additional costs); and


	(2)	the actual construction and acquisition costs paid with respect to the South Texas NGL pipeline (excluding the original pipeline purchase costs of approximately $97.7 million) prior to the contribution of interests in South Texas NGL to us at the closing of this offering.

As of September 30, 2006, we have spent $5.4 million of these estimated additional costs for construction and acquisition of the South Texas NGL pipeline.

Concurrently with the closing of this offering, we will also borrow approximately $200 million under a new credit agreement that we will enter into prior to the closing of this offering. We will distribute $198 million of these borrowings to Enterprise Products OLP in partial consideration for the assets contributed to us upon the closing of this offering. For a description of our credit agreement, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — New Credit Facility.”

If the underwriters exercise their option to purchase additional common units, we will use all of the net proceeds from the sale of those common units to redeem an equal number of common units from Enterprise Products OLP, which may be deemed a selling unitholder in this offering. Please read “Selling Unitholder.”

CAPITALIZATION

The following table sets forth:


	•	the cash and capitalization of our predecessor, Duncan Energy Partners Predecessor, as of June 30, 2006 on a combined historical basis;

	•	our pro forma cash and capitalization as of June 30, 2006, after, giving effect to:


	•	the August 2006 purchase of a pipeline by Enterprise Products Partners for approximately $97.7 million in cash, the subsequent contribution of this pipeline to South Texas NGL, the payment of estimated additional costs of $37.7 million required to modify this pipeline and to acquire and construct additional pipelines in order to place this pipeline system into operation prior to the closing of this offering;

	•	the contribution of a 66% interest in certain entities which are wholly-owned subsidiaries of Enterprise Products Partners, and the retention by Enterprise Products Partners of a 34% interest in these entities;

	•	the revision of related party storage contracts between us and Enterprise Products Partners to (1) increase certain storage fees paid by Enterprise Products Partners and (2) reflect the allocation to Enterprise Products Partners of all storage measurement gains and losses relating to products under these agreements, and the execution of a limited liability company agreement for Mont Belvieu Caverns providing for the special allocation and other agreements relating to other measurement gains and losses to Enterprise Products Partners; and

	•	the assignment to us of certain third-party agreements that effectively reduce tariff rates received by us for the transport of propylene volumes; and


	•	our unaudited pro forma, as adjusted cash and capitalization as of June 30, 2006, after giving effect to the transactions described above, this offering, the borrowing of approximately $200 million under a credit agreement by us in connection with our acquisition of ownership interests in our subsidiaries from Enterprise Products Partners, and the application of the net proceeds from this offering and the borrowings as described under “Use of Proceeds.”

This table is derived from, and should be read together with, the historical combined financial statements of Duncan Energy Partners Predecessor and our unaudited pro forma condensed combined financial information included elsewhere in this prospectus. You should also read this table in conjunction with “Summary — Duncan Energy Partners L.P. — Formation Transactions,” “Use of Proceeds,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus.


	As of June 30, 2006
					Pro Forma,
	Historical		Pro Forma		As Adjusted
	(Dollars in thousands)

Cash	$	—	$	—	$	20,394(a	)

Debt		—		—		200,000
Owner’s net investment — predecessor		557,934		694,106		—
Parent’s interest in Partnership		—		—		275,080
Partnership equity — common units — public		—		—		241,420

Total capitalization	$	557,934	$	694,106	$	716,500


	(a)	Represents cash retained for our 66% share of estimated 2007 capital expenditures to complete planned expansions of our South Texas NGL pipeline.

DILUTION

Dilution is the amount by which the offering price paid by purchasers of our common units sold in this offering will exceed the pro forma net tangible book value per common unit after the offering. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of June 30, 2006, after giving effect to the offering of 13,000,000 common units, our net tangible book value was $275.8 million, or $13.32 per common unit. This amount includes equity from new investors of $241.4 million and the parent’s interest in common units and the general partner interest of $39.1 million less the Partnership’s 66% share of intangible assets. Purchasers of our common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.


Assumed initial public offering price per common unit			$	20.00
Pro forma net tangible book value per common unit before the offering(1)	$	58.79
Decrease in net tangible book value per common unit attributable to purchasers in the offering		45.47

Less: Pro forma net tangible book value per common unit after the offering(2)				13.32

Immediate dilution in net tangible book value per common unit to purchasers in the offering			$	6.68


(1)		Determined by dividing the net tangible book value of the contributed net assets of $689 million, net of subsidiary ownership interests retained by parent of $236 million, by the number of common units (7,298,551 common units and the 2% general partner interest, which has a dilutive effect equivalent to 414,256 common units) to be issued to our general partner and its affiliates for their contribution of assets and liabilities to us. Our general partner’s dilutive effect equivalent was determined by multiplying the total number of common units deemed to be outstanding (i.e., the total number of common units outstanding of 20,298,551 divided by 98%) by our general partner’s 2% general partner interest.

(2)		Determined by dividing our pro forma net tangible book value of $275.8 million, which reflects the application of the assumed net proceeds of this offering, by the total number of common units (20,298,551 common units and the 2% general partner interest, which has a dilutive effect equivalent to 414,256 common units) to be outstanding after the offering. The following table shows our calculation of pro forma net tangible book value (dollars in thousands):


Total consideration amount	$	280,504
Less: 66% share of intangible assets attributable to parent’s interest in common units and the general partner interest and new investors		(4,674	)

	$	275,830

The following table sets forth the number of common units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering (dollars in thousands):


	Common Units					Total
	Acquired					Consideration
	Number		Percent			Amount		Percent

Parent’s interest in common units and general partner interest (1)(2)		7,712,807		37.2	%	$	39,084		14.0	%
New investors		13,000,000		62.8	%		241,420		86.0	%

Total		20,712,807		100.0	%	$	280,504		100.0	%


(1)		Upon the consummation of this offering, Enterprise Products OLP and our general partner will own an aggregate of 7,298,551 common units and a 2% general partner interest having a dilutive effect equivalent to 414,256 common units.


(2)		The assets contributed by Enterprise Products OLP were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and Enterprise Products OLP, as of June 30, 2006, after giving effect to the application of the net proceeds of the offering and the retention of a 34% equity interest in the contributed subsidiaries is as follows (dollars in thousands):


Owners’ net investment	$	694,106
Less: Payment to Parent from the net proceeds of the offering and borrowings under the credit agreement	$	(419,026	)
Less: Parent retention of 34% of the equity interests in contributed subsidiaries of the Partnership	$	(235,996	)

Total consideration for Parent’s interest in common units and general partner interest	$	39,084

For financial reporting purposes, the parent’s retained interest in the subsidiaries of $236 million and the carryover basis in the common units and the general partner interest as part of this offering is presented outside the Partnership equity from the new public investors.

CASH DISTRIBUTION POLICY
AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the specific assumptions included in this section. For detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “— Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma financial information, you should refer to the audited historical combined financial statements of Duncan Energy Partners Predecessor for the years ended December 31, 2003, 2004 and 2005 and the six months ended June 30, 2006 and 2005 and our unaudited pro forma condensed combined financial information at June 30, 2006 and for the year ended December 31, 2005 and six months ended June 30, 2006 included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy

Our partnership agreement requires us to distribute all of our available cash on a quarterly basis. Available cash is defined to mean generally, for each fiscal quarter, all cash and cash equivalents on the date of determination of available cash for such quarter, less the reserves that our general partner determines are necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters. We intend to fund a portion of our capital expenditures with additional borrowings under our new credit facility or the issuance of additional units. We may also borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. Our partnership agreement will not restrict our ability to borrow to pay distributions. It is the current policy of the board of directors of our general partner, however, that we should maintain or increase our level of quarterly cash distributions only when, in its judgment, we can sustain such distribution levels over a long-term period. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it. Also, because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case if we were subject to federal income tax.

Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy is subject to certain restrictions and may be changed at any time, including:


	•	Our cash distribution policy will be subject to restrictions on distributions under our anticipated new credit facility. Specifically, we anticipate that our new credit facility will contain certain material financial tests, such as a leverage ratio and an interest coverage ratio, and other covenants that we must satisfy. Should we be unable to satisfy these restrictions under our new credit facility, or if we otherwise default under our new credit facility, we would be prohibited from making a distribution to you notwithstanding our stated cash distribution policy. These financial tests and covenants are described in the prospectus under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — New Credit Facility.”

	•	Our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish reserves made by our general partner in good faith will be binding on the unitholders. Over a period of time, if we do not set aside sufficient


		cash reserves or make sufficient cash expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. We will not be able to increase our current level of distributions without making accretive acquisitions or capital expenditures that grow our asset base. A significant decrease in throughput volumes or in the demand for or production of hydrocarbon products from current levels would adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions you receive may be considered a return of part of your investment in us as opposed to a return on your investment.


	•	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including our cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units. Following completion of this offering, our public unitholders will own 64.0% of our common units and Enterprise Products Partners (our parent and sponsor) will own the remainder.

	•	Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Enterprise Products OLP owns our general partner.

	•	Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our partners if the distribution would cause our liabilities to exceed the fair value of our assets.

We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including reduced throughput volumes on our pipelines, increased operating or general and administrative expenses, principal and interest payments on any current or future debt, tax expenses, capital expenditures and working capital requirements. Please read “Risk Factors” for a discussion of these factors.

Our Ability to Grow Depends on Our Ability to Access External Growth Capital

Our partnership agreement requires us to distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisition capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. To the extent we issue additional units in connection with any acquisitions or other capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement or our credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance any future growth would result in increased interest expense, which in turn may impact the amount of available cash that we have to distribute to our unitholders.

Our Initial Distribution Rate

Upon completion of this offering, the board of directors of our general partner will adopt a cash distribution policy pursuant to which we will declare an initial distribution of $0.40 per unit per quarter (pro rated for the first quarter during which we are a publicly traded partnership), or $1.60 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. This equates to an aggregate cash distribution of approximately $8.3 million per quarter, or $33.1 million per year, based on the units outstanding immediately after completion of this offering. If the underwriters’ option to purchase additional units is exercised, an equivalent number of common units will be redeemed from Enterprise Products OLP. Accordingly, the exercise of the underwriters’ option to purchase additional units will not affect the total amount of units outstanding or the amount of cash needed to pay the initial distribution rate on all units. Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described

above under the caption “— General — Restrictions and Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. The general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest. Our general partner is not obligated to contribute a proportionate amount of capital to us to maintain its current general partner interest.

The following table sets forth the estimated aggregate distribution amounts payable on our common units and general partner interest during the year following the closing of this proposed offering at our initial distribution rate of $0.40 per common unit per quarter (or $1.60 per common unit on an annualized basis).


	Initial Quarterly Distribution
Units	One Quarter		Four Quarters
	(Dollars in thousands)

Common units	$	8,119	$	32,477
General partner interest		166		663

Total	$	8,285	$	33,140

These distributions will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter at the expected initial quarterly distribution, our unitholders will not be entitled to receive such payments in the future. We will pay distributions on or about the 15th of each February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. On or before May 15, 2007, we expect to pay a distribution to our unitholders equal to the initial quarterly distribution prorated for the portion of the quarter ending March 31, 2007 that we are public.

We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to mean generally, for each fiscal quarter, all cash and cash equivalents on the date of determination of available cash for such quarter, less the reserves that our general partner determines are necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters. Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirements to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial quarterly distribution of $0.40 per common unit per quarter for the four quarters ending December 31, 2007. In those sections we present two tables, including:


	•	Our “Unaudited Pro Forma Combined Available Cash,” in which we present the amount of pro forma available cash that we would have had available for distribution to our limited partners and parent with respect to the year ended December 31, 2005 and four quarters ended June 30, 2006 based on our pro forma financial statements included in this prospectus. Our calculation of pro forma available cash in


		this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been in existence in an earlier period.


	•	Our “Estimated Cash Available to Pay Distributions,” in which we present our estimate of available cash to pay distributions for the four quarters ending December 31, 2007, which supports our belief that we will be able to fully fund our initial annual distribution of $1.60 per common unit during such period.

If we had completed the transactions contemplated in this prospectus on January 1, 2005, our pro forma available cash to pay distributions for the year ended December 31, 2005 would have been $9.9 million. This amount would have been insufficient by approximately $23.2 million to pay the initial annual distribution of $33.1 million on all our common units and general partner interest. Likewise, our pro forma available cash to pay distributions for the four quarters ended June 30, 2006 would have been a deficit of $2.8 million. This amount would have been insufficient by approximately $36 million to pay the initial annual distribution amount of $33.1 million on all our common units and general partner interest.

The pro forma financial information does not reflect certain changes in operating assumptions and expected results that affect our projections for the four quarters ending December 31, 2007, including principally:


	•	The commencement of operations within our NGL Pipeline Services segment. The South Texas NGL pipeline is expected to begin operations in January 2007 and generate an additional $16.4 million of Estimated Consolidated Adjusted EBITDA during the four quarters ending December 31, 2007. For a definition of Estimated Consolidated Adjusted EBITDA, please read “—Estimated Cash Available to Pay Distributions;” and

	•	The funding of expansion capital expenditures with sources other than cash from operations. Because we had no external financing of capital projects in the year ended December 31, 2005 and the four quarters ended June 30, 2006, pro forma available cash was reduced by $19.5 million and $43.3 million for capital expenditures in those respective periods. We expect that, in the future, expansion capital expenditures will be funded with sources other than cash from operations, such as proceeds from this offering, borrowings under our credit facility, debt or equity financings, or contributions from Enterprise Products OLP.

Therefore, we believe that we will have sufficient cash available to pay quarterly distributions of $0.40 per unit on all our common units and our general partner interest during the four quarters ending December 31, 2007. See “— Assumptions and Considerations” for the specific assumptions underlying this belief.

The tables used in this section, “Unaudited Pro Forma Combined Available Cash” and “Estimated Cash Available to Pay Distributions,” have been prepared by, and are the responsibility of our management. Our independent registered public accounting firm has neither examined, compiled or otherwise applied procedures to such information presented herein and, accordingly do not express an opinion or any other form of assurance with respect thereto. Such independent registered public accounting firm’s reports included elsewhere in this prospectus relate to the appropriately described historical financial information. Such reports do not extend to the tables and related information and should not be read to do so. In addition, such tables and information were not prepared with a view toward compliance with published guidelines of the Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information, and were not prepared in accordance with accounting principles generally accepted in the United States of America nor were procedures applied for auditing standards of the Public Company Accounting Oversight Board (United States).

Unaudited Pro Forma Combined Available Cash

The pro forma financial statements, upon which our pro forma combined available cash for distributions is based, do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. Furthermore, cash available for distribution is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. We

derived the amounts of pro forma combined available cash for distribution in the manner described in the table below. As a result, the amount of pro forma combined available cash for distribution should be viewed as only a general indication of the amount of cash available for distribution that we might have generated had we been formed in earlier periods.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2005 and for the four quarters ended June 30, 2006, the amount of cash that would have been available for distribution to the holders of our common units (including Enterprise Products Partners) and our general partner assuming that this offering had been consummated at the beginning of each such period. The pro forma information in the following table gives effect to the contribution of 66% ownership interests in Mont Belvieu Caverns, Acadian Gas, Sabine Propylene and Lou-Tex Propylene, the purchase by Enterprise Products Partners of a pipeline in August 2006 for $97.7 million in cash and additional costs of $37.7 million for modifications and additions to this system, the revision of related party NGL storage contracts, and the assignment of certain third-party propylene transportation agreements, as if they had occurred at the beginning of the periods presented.

Duncan Energy Partners L.P.
Unaudited Pro Forma Combined Available Cash
(Dollars in thousands, except per unit amounts)


				Pro Forma
	Pro Forma			Four Quarters
	Year Ended			Ended
	December 31,			June 30,
	2005			2006

Cash Provided by Operating Activities(a)	$	40,568		$	43,768
Adjustments to derive Consolidated Adjusted EBITDA(a):
Interest expense		532			532
Equity income of unconsolidated affiliates		331			488
Net effect of changes in operating accounts(b)		18,280			19,389
Changes in fair market value of financial instruments for Acadian Gas		(52	)		4
Non-cash gain (loss) on sale of assets		(5	)		7

Consolidated Adjusted EBITDA		59,654			64,188
Pro forma increase in storage revenues(c)		11,610			12,573
Pro forma decrease in operating expense due to allocation of measurement losses by parent(d)		3,055			1,447
Pro forma decrease in transportation revenues(e)		(18,439	)		(18,647	)
Additional expenses of being a public company(f)		(2,500	)		(2,500	)

Pro Forma Consolidated Adjusted EBITDA		53,380			57,061
Less: Cash interest expense(g)		(13,000	)		(13,000	)
Cash distributions to parent by subsidiaries(h)		(13,100	)		(6,393	)
Parent contribution for operating losses		2,122			2,854
Capital expenditures(i)		(19,472	)		(43,340	)

Pro Forma Combined Available Cash	$	9,930		$	(2,818	)

Expected Cash Distributions:
Expected distribution per unit	$	1.60		$	1.60

Distributions to our general partner	$	663		$	663
Distributions on common units held by public unitholders (non-parent)		23,920			23,920
Distributions on common units held by parent		8,558			8,558

Total cash distributions	$	33,141		$	33,141

(Shortfall)	$	(23,211	)	$	(35,959	)

Notes to “Unaudited Pro Forma Combined Available Cash” table:


(a)		Reflects historical combined cash provided by operating activities of Duncan Energy Partners Predecessor for the year ended December 31, 2005 or derived from such predecessor information for the four quarters ended June 30, 2006.

(b)		Primarily reflects the historical combined changes in operating accounts of Duncan Energy Partners Predecessor. Such changes are generally the result of timing of cash receipts from sales and cash payments for purchases and other expenses near the end of each period. We will be able to use borrowings under our expected new $ million revolving credit facility to satisfy discretionary cash needs for working capital requirements and, thereby potentially decrease the use of cash flows from operations to satisfy such needs. Consequently, we do not reflect any adjustments to pro forma combined available cash as a result of working capital components.

(c)		Reflects an increase in related party storage fees charged to Enterprise Products Partners attributable to its use of the storage facilities owned by Mont Belvieu Caverns.

(d)		Reflects the allocation to Enterprise Products Partners of measurement gains and losses relating to products under storage agreements between Enterprise Products Partners and Mont Belvieu Caverns and the execution of a limited liability company agreement with Mont Belvieu Caverns providing for special allocations to Enterprise Products Partners and other agreements relating to other measurement gains and losses.

(e)		Reflects a reduction in transportation rates we charge for usage of the Lou-Tex Propylene and Sabine Propylene pipelines.

(f)		Reflects $2.5 million of our incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded entity. These costs include fees associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, accounting and legal services. These costs also include estimated related party amounts payable to EPCO in connection with the administrative services agreement. For additional information regarding the administrative services agreement, please read “Certain Relationships and Related Party Transactions — Administrative Services Agreement.”

(g)		Reflects $13 million of cash interest cost plus $0.4 million of non-cash amortization related to debt issuance costs resulting from an assumed $200 million borrowed at an estimated variable interest rate of 6.5% per annum under our new credit facility. If the variable interest rate used to calculate this interest expense were 1/8% higher, our annual cash interest cost would increase to $13.3 million.

(h)		Reflects Enterprise Products Partners contributions to (and distributions from) subsidiaries. These amounts are net of the parent’s share of capital expenditures of each subsidiary. Enterprise Products Partners will own a 34% interest in each of our subsidiaries and will be allocated a portion of the cash flows of each subsidiary in accordance with its ownership percentage. However, the parent’s 34% earnings allocation with respect to Mont Belvieu Caverns is after a special allocation by Mont Belvieu Caverns to the parent in an amount equal to the subsidiary’s net measurement gain or loss each period. Enterprise Products Partners will receive a cash distribution from Mont Belvieu Caverns with respect to a net measurement gain each quarter. Conversely, Enterprise Products Partners will make a cash contribution to Mont Belvieu Caverns with respect to a net measurement loss each quarter.

(i)		Reflects actual capital expenditures, net of contributions in aid of construction costs, for growth and sustaining capital projects for the periods indicated. The majority of these capital expenditures were for the construction of additional brine production capacity at the storage facility owned by Mont Belvieu Caverns.

Estimated Cash Available to Pay Distributions

In order for us to pay an initial distribution rate of $0.40 per unit for each quarter in the four quarters ending December 31, 2007, we must generate at least $77.1 million in Estimated Consolidated Adjusted EBITDA during that period. The Estimated Consolidated Adjusted EBITDA should not be viewed as

management’s projection of the actual Consolidated Adjusted EBITDA that we would generate during the four quarters ending December 31, 2007. Estimated Consolidated Adjusted EBITDA of $77.1 million is $23.7 million higher than Pro Forma Consolidated Adjusted EBITDA for the year ended December 31, 2005 and $20 million higher than Pro Forma Consolidated Adjusted EBITDA for the four quarters ended June 30, 2006.

Our definition of EBITDA included under “Summary — Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures” differs from “Estimated Consolidated Adjusted EBITDA.” We define EBITDA as net income or loss plus interest expense, income taxes, depreciation and amortization expense. We defined Estimated Consolidated Adjusted EBITDA as EBITDA before parent interest in earnings. Our measures of EBITDA and Estimated Consolidated Adjusted EBITDA should not be considered alternatives to net income, income from continuing operations, cash flows from operating activities, or any other measure of financial performance calculated in accordance with accounting principles generally accepted in the United States as those items are used to measure operating performance, liquidity or ability to service debt obligations.

We believe that we will be able to generate sufficient Estimated Consolidated Adjusted EBITDA to pay our estimated initial quarterly distribution during each of the four quarters ending December 31, 2007. In “Assumptions and Considerations,” we discuss the major assumptions underlying this belief. We can give you no assurance that our assumptions will be realized or that we will generate the Estimated Consolidated Adjusted EBITDA or the expected level of available cash, in which event we will not be able to pay the initial quarterly distribution of $1.60 per year on our units.

When considering our Estimated Consolidated Adjusted EBITDA, you should keep in mind the risk factors and other cautionary statements, including those under the headings “Risk Factors” and “Forward-Looking Statements,” included in elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our financial condition and consolidated results of operations to vary significantly from those set forth in the table, “Estimated Cash Available to Pay Distributions.”

As a matter of policy, we do not make public projections regarding our future sales, earnings, or other results. However, we have prepared the prospective financial information set forth below to present the table entitled “Estimated Cash Available to Pay Distributions.” We do not undertake any obligation to publicly release the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date in this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

In the following table entitled “Estimated Cash Available to Pay Distributions,” we estimate that our Estimated Consolidated Adjusted EBITDA will be approximately $33.1 million for the four quarters ending December 31, 2007.

Duncan Energy Partners L.P.
Estimated Cash Available to Pay Distributions


	Four Quarters
	Ending
	December 31,
	2007
	(Dollars in thousands)

Estimated Consolidated Adjusted EBITDA	$	77,068
Less: Cash interest expense(a)		(13,000	)
Cash distributions to parent by subsidiaries(b)		(25,058	)
Sustaining capital expenditures(c)		(5,869	)

Estimated Cash Available to Pay Distributions	$	33,141

Expected Cash Distributions:
Annualized initial quarterly distributions per unit	$	1.60
Distributions to our general partner	$	663
Distributions on common units held by public unitholders (non-parent)		23,920
Distributions on common units held by parent		8,558

Total estimated cash distributions	$	33,141

Notes to “Estimated Cash Available to Pay Distributions” table:


(a)		Reflects $13 million of cash interest cost resulting from an assumed $200 million borrowed at an estimated variable interest rate of 6.5% per annum under our new credit facility. If the variable interest rate used to calculate this interest expense were 1/8% higher, our annual cash interest cost would increase to $13.3 million.

(b)		Reflects the cash distributions payable to Enterprise Products Partners attributable to its interest in our subsidiaries. These distributions are net of Enterprise Products Partners’ share of projected capital expenditures for each subsidiary.

(c)		In this table, we have included sustaining capital expenditure estimates for the four quarters ending December 31, 2007. Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to and major renewals of existing assets. Such expenditures serve to maintain (or sustain) existing operations but do not generate additional revenues. For purposes of this table, we are assuming that all of our sustaining capital expenditures for the four quarters ending December 31, 2007 will be funded with cash flow from operations. We may, however, borrow under our new revolving credit facility to fund certain of our sustaining capital expenditure needs. Borrowings to fund capital expenditures would result in increased interest expense. This table does not include $20.4 million for the expansion of the South Texas NGL pipeline system, which we expect to fund with proceeds from this offering, any expenditures for the currently contemplated Mont Belvieu expansion projects, which we expect to fund with borrowings under our credit facility, equity or debt financings, or contributions from Enterprise Products OLP, or any other expansion capital expenditures.

Assumptions and Considerations

Based upon the specific assumptions outlined below with respect to the four quarters ending December 31, 2007, we expect to generate cash flow from operations in an amount sufficient to pay the initial quarterly distribution on all units through December 31, 2007.

While we believe that these assumptions are reasonable in light of management’s current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions do not materialize, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full initial quarterly distribution (absent borrowings under our credit facility), or any amount, on all units, in which event the market price of our units may decline substantially.

Over a period of time, if we do not set aside sufficient cash reserves or make sufficient cash expenditures to maintain our asset base, we will be unable to pay distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions. We will not be able to sustain our current level of distributions without making accretive acquisitions or capital expenditures that maintain or grow our asset base. Decreases in throughput volumes or an increase in natural gas prices from current levels will adversely affect our ability to pay distributions. If our asset base decreases and we do not reduce our distributions, a portion of the distributions you receive may be considered a return of part of your investment in us as opposed to a return on your investment.

Revenues

The following table shows the selected operating data and segment revenues that support our Estimated Consolidated Adjusted EBITDA for the four quarters ending December 31, 2007 along with a comparison of historical volumetric and revenue data underlying our Pro Forma Consolidated Adjusted EBITDA for the year ended December 31, 2005 and four quarters ended June 30, 2006.


			Four Quarters		Four Quarters
	Year Ended		Ended		Ending
	December 31,		June 30,		December 31,
	2005		2006		2007

Operating data (on a 100% basis): (a)
Natural gas throughput, net (Bbtu/d)(b)		640		703		700
NGL transportation, net (MBPD)(c)						68
Petrochemical transportation, net (MBPD)(d)		33		32		37
Pro forma segment revenues (dollars in millions):
Natural Gas Pipelines & Services(e)	$	866.7	$	966.4	$	738.4
NGL & Petrochemical Storage Services(f)		64.4		70.2		75.8
NGL Pipeline Services(c)						20.6
Petrochemical Pipeline Services(d)		15.5		14.5		14.9

Total pro forma revenues	$	946.6	$	1,051.1	$	849.7

Notes to “Revenues” table:


(a)		Operating data presented in the preceding table for the year ended December 31, 2005 and four quarters ended June 30, 2006 reflect actual volumes.

(b)		Natural gas throughput represents combined transportation and sales volumes for the Acadian Gas pipeline system, including our 50% share of Evangeline’s transportation volumes. Throughput volumes forecast for 2007 on the Acadian Gas system are expected to be 63 billion British thermal units per day, or Bbtu/d, higher than those posted for the year ended December 31, 2005. The increase in transportation volumes between the two periods is primarily due to the addition of new customers and an increase in transport activity by customers related to pricing differentials. Throughput volumes for the four quarters ended December 31, 2007 are based on similar levels realized during the four quarters ending June 30, 2006.

(c)		We expect the South Texas NGL pipeline will become operational in January 2007. No volumetric data or revenue information is provided for the year ended December 31, 2005 and four quarters ended June 30, 2006. The estimated volumes shown in this table are based on expected production at Enterprise Products


		Partners’ Shoup and Armstrong fractionation facilities. We expect production from these facilities in 2007 to be slightly higher than production levels in 2006 due to higher processed gas volumes in the South Texas region.

(d)		We expect petrochemical transportation volumes for the four quarters ending December 31, 2007 to exceed realized volumes for the year ended December 31, 2005 and four quarters ended June 30, 2006. Throughput volumes on these pipelines were lower following Hurricanes Katrina and Rita in 2005. The change in revenues between periods is primarily attributable to the change in volumes.

(e)		The period-to-period fluctuation in revenues from our Natural Gas Pipelines & Services segment is largely due to changes in the price of natural gas. Revenues from this segment are primarily generated from the sale of natural gas to customers in South Louisiana (using industry index prices). The market price of natural gas, as measured at Henry Hub in Louisiana, averaged $8.64 per MMBtu and $9.34 per MMBtu for the year ended December 31, 2005 and four quarters ended June 30, 2006, respectively. Forecast revenues for the year ended December 31, 2007 are based on an estimated natural gas price of $8.20 per MMBtu. As of October 31, 2006, the Henry Hub spot price for natural gas was expected (based on an average monthly price of NYMEX futures for 2007 deliveries) to average $7.90 per MMBtu in 2007.

(f)		Revenues from our NGL & Petrochemical Storage Services segment for the year ended December 31, 2007 are $11.4 million higher than those presented for the year ended December 31, 2005. Revenues for the four quarters ending December 31, 2007 are $5.6 million higher than those presented for the four quarters ended June 30, 2006. The increase in revenues for the 2007 period relative to the pro forma periods is primarily due to the renegotiation of related-party revenue contracts with Enterprise Products Partners.

Costs and Expenses

The following table shows the components of costs and expenses used to determine our Estimated Consolidated Adjusted EBITDA for the four quarters ending December 31, 2007 along with a comparison of cost and expense data underlying our Pro Forma Consolidated Adjusted EBITDA for the year ended December 31, 2005 and four quarters ended June 30, 2006.


			Four Quarters		Four Quarters
	Year Ended		Ended		Ending
	December 31,		June 30,		December 31,
	2005		2006		2007

Cost and expense data (dollars in millions):
Cost of natural gas sales(a)	$	836.5	$	936.4	$	706.9
Operating costs and expenses, excluding non-cash costs(b)		51.7		55.0		59.2
General and administrative costs, including pro forma incremental public company costs(c)		7.0		6.3		6.5

Total	$	895.2	$	997.7	$	772.6

Notes to “Costs and Expenses” table:


(a)		The period-to-period change in the cost of natural gas sales is largely due to changes in the price of natural gas. We purchase natural gas at industry index-based prices to satisfy our contractual sales obligations. The market price of natural gas, as measured at Henry Hub in Louisiana, averaged $8.64 per MMBtu and $9.34 per MMBtu for the year ended December 31, 2005 and four quarters ended June 30, 2006, respectively. Forecast revenues for the year ended December 31, 2007 are based on an estimated natural gas price of $8.20 per MMBtu. As of October 31, 2006, the Henry Hub spot price for natural gas was expected (based on an average monthly price of NYMEX futures for 2007 deliveries) to average $7.90 per MMBtu in 2007.

(b)		We forecast our operating costs and expenses for the four quarters ending December 31, 2007 to approximate $59.2 million. This amount is $7.5 million higher than pro forma operating costs and expenses for the year ended December 31, 2005 and $4.2 million higher than those for the four quarters ended June 30, 2006. The 2007 period includes $3.7 million of operating costs and expenses associated with our South


		Texas NGL pipeline system, which is scheduled to commence operations in January 2007. In addition, forecast operating costs and expenses for 2007 includes pipeline integrity-related expenses of $2.8 million, which is $2 million higher than those recorded for the year ended December 31, 2005 and $1.1 million higher than those for the four quarters ended June 30, 2006.

(c)		Costs and expenses for all periods include the pro forma effect of $2.5 million of incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded entity. These costs include fees associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, accounting and legal services. These costs also include estimated related party amounts payable to EPCO, Inc. in connection with the administrative services agreement. For additional information regarding the administrative services agreement, please read “Certain Relationships and Related Party Transactions — Administrative Services Agreement.” Estimated general and administrative costs for the four quarters ending December 31, 2007 include $0.6 million attributed to our South Texas NGL pipeline system.

Capital Expenditures

Our capital expenditures consist of sustaining capital expenditures and those related to growth projects. Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to and major renewals of existing assets. Such expenditures serve to maintain (or sustain) existing operations but do not generate additional revenues. Growth capital spending relates to projects that (i) result in additional revenue streams from existing assets or (ii) expand our asset base through construction of new facilities that will generate additional revenue streams.

Combined capital spending, net of contributions in aid of construction costs, was $19.5 million for the year ended December 31, 2005 and $43.3 million for the four quarters ended June 30, 2006. Construction of additional brine production capacity and above-ground storage reservoirs at the facility owned by Mont Belvieu Caverns accounted for $11.4 million and $36.7 million of capital expenditures for the year ended December 31, 2005 and six months ended June 30, 2006. All of these projects are estimated to be completed and placed in service by the end of January 2007. The remainder of combined capital spending for the year ended December 31, 2005 and six months ended June 30, 2006 is attributable to sustaining capital projects, the majority of which relate to pipeline integrity projects.

During 2007, we expect that South Texas NGL will make capital expenditures of $30.9 million to complete planned expansions to the South Texas NGL pipeline system. We expect to fund our share of these expenditures (approximately $20.4 million) with proceeds from this offering. We may also incur $25 million to $75 million of additional expansion capital expenditures in 2007 in connection with currently contemplated expansion projects at Mont Belvieu Caverns. We expect to finance any such projects through borrowings under our credit facility, the issuance of debt or additional equity, or contributions from Enterprise Products OLP. The tables in this section do not reflect these planned and potential capital expenditures.

Our Estimated Cash Available to Pay Distributions for the four quarters ending December 31, 2007 includes an anticipated $5.9 million of sustaining capital expenditures.

Interest Cost

Our interest cost reflects $13 million of cash interest cost resulting from an assumed $200 million borrowed at an estimated variable interest rate of 6.5% per annum under our new credit facility. If the variable interest rate used to calculate this interest expense were 1/8% higher, our annual cash interest cost would increase to $13.3 million.

HOW WE MAKE CASH DISTRIBUTIONS

Following is a description of the relative rights and preferences of holders of our common units in and to cash distributions. The information presented in this section assumes that our general partner continues to make capital contributions to Duncan Energy Partners in order to maintain its 2% general partner interest in Duncan Energy Partners.

Distributions of Available Cash

General. Within approximately 45 days after the end of each quarter, commencing with the quarter ending on March 31, 2007, we will distribute all of our available cash to unitholders of record on the applicable record date. We will distribute 98% of our available cash to our common unitholders, pro rata, and 2% to our general partner. Unlike many publicly traded limited partnerships, our general partner is not entitled to any incentive distributions and we do not have any subordinated units.

Definition of Available Cash. Available cash is defined in our partnership agreement and generally means, with respect to any fiscal quarter, all cash and cash equivalents on the date of determination of available cash for such quarter:


	•	less the amount of cash reserves established by the general partner:


	•	provide for the proper conduct of our business (including reserves for future capital expenditures and for our future credit needs);

	•	comply with applicable law or any debt instrument or other agreement; or

	•	provide funds for distributions to unitholders and our general partner in respect of any one or more of the next four quarters.

Distributions of Cash upon Liquidation

If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called a liquidation. We will first apply the proceeds of liquidation to the payment of our creditors and the liquidator in the order of priority provided in our partnership agreement and by law and, thereafter, we will distribute any remaining proceeds to our unitholders and our general partner in accordance with their respective capital account balances as so adjusted.

Manner of Adjustments for Gain. The manner of the adjustment is set forth in our partnership agreement. Upon our liquidation, we will allocate any net gain (or unrealized gain attributable to assets distributed in kind to our partners) as follows:


	•	first, to our general partner and the holders of our common units having negative balances in their capital accounts to the extent of and in proportion to such negative balances; and

	•	thereafter, 98% to all of our unitholders, pro rata, and 2% to our general partner.

Manner of Adjustments for Losses. Upon our liquidation, any loss will generally be allocated to our general partner and our unitholders as follows:


	•	first, 98% to the holders of our common units in proportion to the positive balances in their respective capital accounts and 2% to our general partner, until the capital accounts of our unitholders have been reduced to zero; and

	•	thereafter, 100% to our general partner.

Adjustments to Capital Accounts. In addition, interim adjustments to capital accounts will be made at the time we issue additional partnership interests or make distributions of property. Such adjustments will be based on the fair market value of the partnership interests or the property distributed and any gain or loss resulting therefrom will be allocated to our unitholders and our general partner in the same manner as gain or loss is allocated upon liquidation. In the event that positive interim adjustments are made to the capital accounts, any subsequent negative adjustments to the capital accounts resulting from the issuance of additional partnership interests in us, distributions of property by us, or upon our liquidation, will be allocated in a manner which results, to the extent possible, in the capital account balances of our general partner equaling the amount that would have been the general partner’s capital account balances if no prior positive adjustments to the capital accounts had been made.

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

Duncan Energy Partners L.P. was formed on September 29, 2006; therefore, it does not have any historical financial statements prior to its formation. The following tables set forth, for the periods and at the dates indicated, the selected historical combined financial and operating data of Duncan Energy Partners Predecessor, which was derived from the books and records of Enterprise Products Partners.

The selected historical financial data for the years ended December 31, 2005, 2004 and 2003 and combined balance sheet data at December 31, 2005 and 2004 is derived from and should be read in conjunction with the audited combined financial statements of Duncan Energy Partners Predecessor included elsewhere in this prospectus beginning on page F-13. The selected historical financial and operating data for the six months ended June 30, 2006 and 2005 and combined balance sheet at June 30, 2006 is derived from and should be read in conjunction with the unaudited condensed combined financial statements of Duncan Energy Predecessor included elsewhere in this prospectus beginning on page F-42. The operating data for all periods are unaudited. The selected unaudited pro forma combined financial data of Duncan Energy Partners was derived from and should be read in conjunction with our unaudited pro forma condensed combined financial statements included in this prospectus beginning on page F-2. The following information should be read together with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Enterprise Products Partners, through its subsidiaries, has owned controlling interests and operated the underlying assets of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene for several years. Enterprise Products Partners will retain a 34% ownership interest in each of these four entities (as well as South Texas NGL). Enterprise Products Partners will own our general partner, DEP Holdings, which owns a 2% general partner interest in us, and therefore indirectly has the ability to control us. In addition, Enterprise Products Partners will own approximately 36.0% of our outstanding common units after completion of this proposed offering, or approximately 26.3% of our outstanding common units if the underwriters exercise their option to purchase additional common units in full. For financial reporting purposes, the ownership interests of Enterprise Products Partners are deemed to represent the parent (or sponsor) interest in our pro forma results of operations and financial position.

Our selected unaudited pro forma combined financial data give effect to the following significant transactions and events:


	•	The August 2006 purchase of a pipeline by Enterprise Products Partners for approximately $97.7 million in cash, the subsequent contribution of this pipeline to South Texas NGL, and estimated additional costs of $37.7 million (including $8 million to acquire a pipeline asset from TEPPCO Partners) required to modify this pipeline and to acquire and construct additional pipelines in order to place this system into operation in January 2007. The pro forma financial data does not reflect estimated additional capital expenditures of $30.9 million that will be made by South Texas NGL in 2007 to complete planned expansions to this system. We will retain cash in an amount equal to our 66% share (approximately $20.4 million) of these estimated capital expenditures from the net proceeds of this offering in order to fund our share of the planned expansion costs. The pro forma combined results of operations data does not reflect any results attributable to the historical activities of this pipeline.

	•	The contribution of a 66% interest in each of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL, all of which are wholly-owned subsidiaries of Enterprise Products Partners, and the retention of Enterprise Products Partners of a 34% interest in these entities.

	•	The revision of related party storage contracts between us and Enterprise Products Partners to (1) increase certain storage fees paid by Enterprise Products Partners and (2) reflect the allocation to Enterprise Products Partners of all storage measurement gains and losses relating to products under these agreements, and the execution of a limited liability company agreement for Mont Belvieu Caverns providing for the special allocation and other agreements relating to other measurement gains and losses to Enterprise Products Partners.


	•	The assignment to us of certain third-party agreements that effectively reduce tariff rates received by us compared to rates previously charged by Lou-Tex Propylene and Sabine Propylene to Enterprise Products Partners for the transport of propylene volumes.

Our unaudited pro forma, as adjusted financial data also gives effect to the following:


	•	our borrowing of $200 million under a new bank credit facility;

	•	our issuance and sale of 13,000,000 common units in this offering;

	•	our payment of estimated underwriting discounts and commissions, a structuring fee and other offering expenses; and

	•	our use of net proceeds from the borrowing and this offering as consideration for the contributed ownership interests in Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL from Enterprise Products Partners.

The selected unaudited pro forma combined financial data for the six months ended June 30, 2006 and for the year ended December 31, 2005 assume the pro forma transactions noted herein occurred at the beginning of each period presented or on June 30, 2006 for the balance sheet data.

The following table presents the selected historical combined financial and operating data of Duncan Energy Partners Predecessor and our selected pro forma financial information for the annual periods indicated (dollars in thousands, except per unit amounts):


															Duncan Energy Partners L.P.
															For the Year Ended
	Duncan Energy Partners Predecessor														December 31, 2005
	For the Year Ended December 31,														Pro			Pro Forma
	2001			2002			2003		2004			2005			Forma			As Adjusted

Combined Results of Operations Data:(1)
Revenues	$	427,857		$	533,829		$	668,234	$	748,931		$	953,397		$	946,568		$	946,568
Costs and expenses:
Operating costs and expenses		385,140			472,171			609,774		685,544			909,044			905,989			905,989
General and administrative expenses		5,851			6,302			6,138		5,442			4,483			6,983			6,983

Total costs and expenses		390,991			478,473			615,912		690,986			913,527			912,972			912,972

Equity in income (loss) of unconsolidated affiliates		(145	)		(58	)		131		231			331			331			331

Operating income		36,721			55,298			52,453		58,176			40,201			33,927			33,927

Interest expense													(532	)		(532	)		(13,932	)
Other income (expense), net		448			113			1		(52	)

Total other income (expense)		448			113			1		(52	)		(532	)		(532	)		(13,932	)

Income before parent interest		37,169			55,411			52,454		58,124			39,669			33,395			19,995
Parent’s share of income																			(14,226	)

Income from continuing operations		37,169			55,411			52,454		58,124			39,669		$	33,395		$	5,769

Cumulative effect of change in accounting principle													(582	)

Net income	$	37,169		$	55,411		$	52,454	$	58,124		$	39,087

Earnings per unit — public, basic and diluted																		$	0.44

Combined Balance Sheet Data (at period end):(1)
Total assets	$	482,436		$	594,455		$	581,816	$	590,487		$	642,840
Owners’ net investment — predecessor		433,750			536,066			524,127		509,719			527,767
Other Combined Financial Data:(1)
Net cash flows provided by operating activities	$	53,043		$	81,528		$	64,732	$	79,463		$	40,568
Cash flows used in investing activities		29,241			145,129			340		6,931			19,503
Cash flows used in (provided by) financing activities(2)		13,585			(39,891	)		64,392		72,532			21,065
Gross operating margin								76,473		81,985			64,142		$	60,368		$	60,368
EBITDA								70,336		76,498			59,072			53,380			39,154
Operating Data:(1)
Natural Gas Pipelines & Services, net:
Natural gas throughput volumes (Bbtus/d)		783			700			600		645			640			640			640
Petrochemical Pipeline Services, net:
Petrochemical transportation volumes (MBbls/d)		27			35			40		39			33			33			33

The following table presents the selected historical combined financial and operating data of Duncan Energy Partners Predecessor and our pro forma combined financial information for the interim periods indicated (dollars in thousands, except per unit amounts):


	Duncan Energy					Duncan Energy Partners L.P
	Partners Predecessor					For the Six Months
	For the Six Months					Ended June 30, 2006
	Ended June 30,					Pro			Pro Forma
	2005		2006			Forma			As Adjusted

Combined Results of Operations Data:(1)
Revenues	$	400,029	$	503,791		$	499,210		$	499,210
Costs and expenses:
Operating costs and expenses		377,779		478,586			478,309			478,309
General and administrative expenses		2,436		1,735			2,985			2,985

Total costs and expenses		380,215		480,321			481,294			481,294

Equity in income of unconsolidated affiliates		197		354			354			354

Operating income		20,011		23,824			18,270			18,270

Interest expense										(6,647	)
Other income (expense), net				4			4			4

Total other income (expense)				4			4			(6,643	)

Income before provision for income taxes and parent interest		20,011		23,828			18,274			11,627
Provision for income taxes				(21	)		(21	)		(21	)

Income before parent interest		20,011		23,807			18,253			11,606
Parent’s share of income										(7,895	)

Income from continuing operations		20,011		23,807		$	18,253		$	3,711

Cumulative effect of change in accounting principle				9

Net income	$	20,011	$	23,816

Earnings per unit — public, basic and diluted									$	0.29

Combined Balance Sheet Data (at period end):(1)
Total assets	$	590,060	$	626,721		$	762,089		$	784,483
Total debt										200,000
Parent’s interest in the Partnership										275,080
Owners’ net investment — predecessor		515,465		557,934			694,106			—
Partners’ equity — public										241,420
Other Combined Financial Data:(1)
Net cash flows provided by operating activities	$	23,676	$	26,876
Cash flows used in investing activities		9,409		33,227
Cash flows used in (provided by) financing activities(2)		14,267		(6,351	)
Gross operating margin		31,878		35,695		$	31,391		$	31,391
EBITDA		29,443		33,986			28,423			20,528
Operating Data:(1)
Natural Gas Pipelines & Services, net:
Natural gas throughput volumes (Bbtus/d)		663		789			789			789
Petrochemical Pipeline Services, net:
Petrochemical transportation volumes (MBbls/d)		38		35			35			35

The non-GAAP financial measures of gross operating margin and earnings before interest, income taxes, depreciation and amortization, which we refer to as “EBITDA,” are presented in the selected historical and pro forma financial data for Duncan Energy Partners Predecessor. For a description of the non-GAAP financial measures that we use in this prospectus and reconciliations of such non-GAAP financial measures to their most directly comparable financial measure or measures calculated and presented in accordance with GAAP, please read “Summary — Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.”

(1) We view the combined financial statements of Duncan Energy Partners Predecessor as the predecessor of the Partnership, a Delaware limited partnership formed on September 29, 2006. The financial statements of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene combined to create Duncan Energy Partners Predecessor were derived from the accounts and records of Enterprise Products Partners, which did not own certain of the businesses for all periods presented in this “Selected Historical and Pro Forma Financial and Operating Data” section. As a result, the selected data reflects the following information:


	•	Enterprise Products Partners owned Mont Belvieu Caverns and Lou-Tex Propylene for all periods presented.

	•	Enterprise Products Partners acquired Acadian Gas in April 2001; therefore, the selected data includes Acadian Gas from the date of its acquisition. No financial data was available from the seller prior to April 2001.

	•	Enterprise Products Partners constructed the pipeline owned by Sabine Propylene and placed it in service in November 2001; therefore, the selected data includes Sabine Propylene from November 2001 to present.

	•	In August 2006, Enterprise Products Partners purchased 223 miles of NGL pipelines extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The total purchase price for this asset was approximately $97.7 million in cash. This pipeline system will be owned by South Texas NGL (along with others being constructed and to be acquired) and will be used to transport NGLs from two Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas. The total estimated cost to acquire and construct the additional pipelines is $68.6 million. Our pro forma balance sheet data reflects assumed capital expenditures of $37.7 million, including approximately $8 million to purchase a 10-mile pipeline from an affiliate, TEPPCO Partners, to make this pipeline system operational prior to the closing of this offering. We expect that it will cost an additional $30.9 million to complete planned expansions of the South Texas NGL pipeline after the closing of this offering, of which our 66% share will be approximately $20.4 million. This expenditure is not reflected in the pro forma financial data because we expect to use cash on hand from the proceeds of this offering to fund this cost.

Duncan Energy Partners Predecessor’s historical financial information does not reflect any transactions related to the NGL pipeline asset acquired in August 2006 or subsequent capital expenditures for the construction and acquisition of related pipelines. Furthermore, the pro forma adjustments are limited to those required to present an estimate of owners’ net investment immediately prior to the Partnership’s initial public offering. The pro forma income statements do not reflect any results of operations attributable to the historical activities of the existing NGL pipelines.

With respect to the pipeline acquired in August 2006, the seller has informed us that no discrete and separable financial information existed for the pipeline, which was comprised of two separately operated pipelines prior to our purchase. The seller had previously utilized these pipelines for a different product and the pipeline was out of service when we acquired it. With respect to the 10-mile pipeline to be purchased from TEPPCO Partners, this pipeline was used as a feeder line for NGL products and operated by different

management. We understand no financial statements information is available for this minor component asset. There is no meaningful financial data available regarding the prior use of these pipelines by the sellers that would be meaningful to our investors. In addition, such data, if available, would not assist investors in understanding either the evolution of the business (which is a new NGL transportation network) nor the track record of management (which will be different).

(2) Duncan Energy Partners Predecessor operated within the Enterprise Products Partners cash management program for all periods presented. Cash flows used in financing activities represent transfers of excess cash from Duncan Energy Partners Predecessor to Enterprise Products Partners equal to cash provided by operations less cash used in investing activities. Conversely, cash flows provided by financing activities represent contributions from Enterprise Products Partners. These cash transfers have been reflected in owner’s net investment.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The historical combined financial statements included in this prospectus reflect assets, liabilities and operations to be contributed to us by Enterprise Products Partners L.P. and various wholly owned subsidiaries upon the closing of this offering. We refer to these assets, liabilities and operations as the assets, liabilities and operations of Duncan Energy Partners Predecessor. The following discussion analyzes the financial condition and results of operations of Duncan Energy Partners Predecessor, which reflects ownership of 100% of the assets, liabilities and operations to be contributed to us. However, we will only have a 66% interest in the assets, liabilities and operations being contributed to us, and Enterprise Products Partners will retain the remaining 34% interest. You should read the following discussion of the financial condition and results of operations for Duncan Energy Partners Predecessor in conjunction with the historical combined financial statements and notes of Duncan Energy Partners Predecessor and the unaudited pro forma condensed combined financial statements for Duncan Energy Partners L.P. included elsewhere in this prospectus.

Overview

We are a Delaware limited partnership formed by Enterprise Products Partners in September 2006 to own, operate and acquire a diversified portfolio of midstream energy assets. Our operations currently are organized into the following three business segments:


	•	our NGL & Petrochemical Storage Services segment, which consists of 33 salt dome caverns located in Mont Belvieu, Texas, with an underground storage capacity of approximately 100 MMBbls, and certain related assets;

	•	our Natural Gas Pipelines & Services segment, which consists of an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana;

	•	our Petrochemical Pipeline Services segment, which consists of two petrochemical pipeline systems totaling 284 miles, including the 263-mile Lou-Tex propylene pipeline system and the 21-mile Sabine propylene pipeline system; and

Our South Texas NGL pipeline system is scheduled to become operational in January 2007. This business will be accounted for under a fourth reporting segment, NGL Pipeline Services. The South Texas NGL pipeline system will consist of a 290-mile pipeline system used to transport NGLs from two of Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas and related interconnections. The historical combined financial statements of Duncan Energy Partners Predecessor do not include any results of this segment.

Our operating revenues from each of our segments (other than our NGL Pipeline Services segment which will not be operational until January 2007), and their relative percentages of our total revenues, consisted of the following (dollars in millions):


										Six Months Ended
	Year Ended December 31,									June 30,
	2005			2004			2003			2006			2005

Revenues:
NGL & Petrochemical Storage Services	$	52.8	5%	$	49.5	7%	$	49.4	7%	$	27.8	5%	$	23.0	6%
Natural Gas Pipelines & Services		866.7	91%		658.4	88%		576.5	86%		457.7	91%		357.9	89%
Petrochemical Pipeline Services		33.9	4%		41.0	5%		42.3	7%		18.3	4%		19.1	5%

Total revenues	$	953.4	100%	$	748.9	100%	$	668.2	100%	$	503.8	100%	$	400.0	100%

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


										Six Months Ended
	Year Ended December 31,									June 30,
	2005			2004			2003			2006			2005

NGL & Petrochemical Storage Services(1)	$	16,636	26%	$	19,843	24%	$	19,838	26%	$	8,871	25%	$	5,705	18%
Natural Gas Pipelines & Services(1)		18,939	30%		25,256	31%		18,272	24%		10,881	30%		9,116	29%
Petrochemical Pipeline Services(1)		28,567	44%		36,886	45%		38,363	50%		15,943	45%		17,057	53%

Total segment gross operating margin(1)	$	64,142	100%	$	81,985	100%	$	76,473	100%	$	35,695	100%	$	31,878	100%


(1)		Please read “Summary — Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures” for a reconciliation of total segment gross operating margin to operating income.

Our segment operating assets will be held by various subsidiaries. In connection with this offering, Enterprise Products OLP will contribute to us equity interests representing a 66% interest in the following subsidiaries:


	•	Mont Belvieu Caverns;

	•	Acadian Gas;

	•	Sabine Propylene and Lou-Tex Propylene; and

	•	South Texas NGL (the assets of which are scheduled to be operational in January 2007).

Our Operations

NGL & Petrochemical Storage Services Segment. Our NGL & Petrochemical Storage Services segment consists of 33 salt dome caverns located in Mont Belvieu, Texas, with an underground storage capacity of approximately 100 MMBbls, and certain related assets. These assets receive, store and deliver NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States.

We charge our customers monthly storage reservation fees to reserve a specific storage capacity in our underground caverns to meet their storage requirements. Customers pay reservation fees based on the quantity of capacity reserved even if that capacity is not actually utilized. When a customer exceeds its reserved capacity, we will charge those customers an excess storage fee. In addition, we charge our customers throughput fees based on volumes injected and withdrawn from the storage facility. Lastly, brine production revenues are derived from customers that use brine in the production of feedstocks for production of polyvinyl chloride (PVC).


	•	multi-product fungible storage contracts, which allow customers to store any combination of fungible products; and

	•	segregated product storage contracts, which are available to customers who desire to store non-fungible products such as propylene, ethylene and naphtha.

We evaluate pricing, volume and availability for storage on a case-by-case basis. Segregated storage allows a customer to lease an entire storage cavern and have its own product injected and withdrawn without having its product commingled.

Natural Gas Pipelines & Services Segment. Our Natural Gas Pipelines & Services segment consists of the Acadian Gas system, which is an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor.

Natural gas throughput in our Natural Gas Pipelines & Services segment consists of a combination of natural gas marketing sales volumes and transportation volumes delivered on behalf of third-party shippers, with marketing volumes and transportation volumes representing approximately 40% and 60%, respectively, of the average daily gas volumes for the first six months of 2006.

In our gas marketing activities, we purchase natural gas supplies for our gas marketing business under contracts with quantities and market-based pricing indices that correspond to the quantities and the pricing indices utilized in our gas sales activities, thereby limiting our commodity price risk. We do not enter into “back-to-back” agreements in which the terms of any purchase agreement are matched directly with any sales agreement.

In addition to our gas marketing activities, the Natural Gas Pipelines & Services segment provides fee-based gas transportation services for producers and gas marketing companies under intrastate and Section 311 interruptible transportation contracts. The primary term of these transportation service contracts may vary from month-to-month to longer-term contracts, with durations typically of one to three years. The revenues derived from these gas transportation contracts are based on the quantities of gas delivered multiplied by the per-unit transportation rate paid.

Our Natural Gas Pipelines & Services segment includes our indirect ownership of 49.5% of the ownership interests in the Evangeline pipeline, a 27-mile pipeline extending from Taft, Louisiana to Westwego, Louisiana. The Natural Gas Pipelines & Services segment’s most significant natural gas sales contract is a 21-year arrangement with Evangeline, which was entered into in 1991, and includes minimum annual quantities. Evangeline uses these natural gas volumes to meet its own supply obligation under a corresponding sales agreement with Entergy Louisiana, its only customer. We include equity earnings from Evangeline in our measurement of segment gross operating margin and operating income. Our equity investments in midstream energy operations, such as those conducted by Evangeline, are a vital component of our long-term business strategy and important to the operations of our Natural Gas Pipelines & Services segment.

Our combined Natural Gas Pipelines & Services segment revenues and operating costs and expenses are significantly influenced by changes in natural gas prices. In general, higher natural gas prices result in increased revenues from the sale of natural gas; however, these same higher commodity prices also increase the associated cost of sales as purchase prices rise.

Petrochemical Pipeline Services Segment. Our Petrochemical Pipeline Services segment consists of two petrochemical pipeline systems with an aggregate of 284 miles of pipeline. The Lou-Tex propylene pipeline system consists of a 263-mile pipeline used to transport chemical-grade propylene between Sorrento, Louisiana and Mont Belvieu, Texas. The Sabine propylene pipeline system consists of a 21-mile pipeline used to transport polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect in Cameron Parish, Louisiana on a transport-or-pay basis.

Shell and ExxonMobil are the only customers that use the Lou-Tex pipeline. We have entered into separate product exchange agreements with Shell and ExxonMobil through which we agree to receive

propylene product in one location and deliver like product to another location. The following is a summary of certain terms of our exchange agreements for the use of the Lou-Tex propylene pipeline:


	•	Shell Exchange Agreement. This agreement expires on March 1, 2020, but will continue on an annual basis subject to termination by either party. The exchange fees paid by Shell are fixed until such time as a published power index in Louisiana becomes available and the parties agree to use such index. Shell is obligated to meet minimum delivery requirements under this agreement. If Shell fails to meet these requirements, it will be obligated to pay us a deficiency fee.

	•	ExxonMobil Exchange Agreement. This agreement expires on June 1, 2008, but will continue on a monthly basis subject to termination by either party. The exchange fees paid by ExxonMobil are based on the volume of chemical grade propylene delivered to us.

Shell is the only current customer that uses the Sabine propylene pipeline. We are a party to a product exchange agreement with Shell for the use of the Sabine propylene pipeline. This agreement expires on November 1, 2011, but will continue on an annual basis subject to termination by either party. The exchange fees paid by Shell are adjusted yearly based on the U.S. Department of Labor wage index and the yearly operating costs of the Sabine pipeline. Shell is obligated to meet minimum delivery requirements under this agreement. If Shell fails to meet these minimum delivery requirements, it will be obligated to pay us a deficiency fee.

NGL Pipeline Services Segment. Our NGL Pipeline Services segment will consist of a 290-mile pipeline system used to transport NGLs from two Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas and related interconnections. We acquired a 223-mile segment of the system in August 2006, and we are in the process of acquiring and constructing other segments of the pipeline system. The system is not in operation, but it is currently undergoing modifications, extensions and interconnections that should allow it to transport NGLs beginning in January 2007. Additional expansions are scheduled to be completed during 2007.

The sole customer of our NGL Pipeline Services segment will be Enterprise Products Partners, which will use the South Texas NGL pipeline system to ship the following products to Mont Belvieu, Texas:


	•	NGLs processed at its Shoup fractionation plant in Corpus Christi, Texas;

	•	NGLs processed at its Armstrong fractionation plant located near Victoria, Texas; and

	•	NGLs purchased by Enterprise Products Partners from third parties in South Texas.

Upon the closing of this offering, we will enter into a ten-year transportation contract with Enterprise Products Partners that will include all of the volumes of NGLs transported on the South Texas NGL pipeline system. Under this contract, Enterprise Products Partners will pay us a dedication fee of $0.02 per gallon for all NGLs produced at the Shoup and Armstrong fractionation plants. This dedication fee is payable whether or not Enterprise Products Partners ships any NGLs on the South Texas NGL pipeline system. For the six months ended June 30, 2006, the Shoup and Armstrong fractionation plants collectively produced 65,250 Bbls/d of NGLs. We will not take title to the products transported on the South Texas NGL pipeline system; rather, Enterprise Products Partners will retain title and the associated commodity risk.

How We Evaluate Our Operations

Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) pipeline volumes, (2) gross operating margin and (3) EBITDA.

Pipeline Throughput Volumes. We view pipeline throughput volumes as an important component of maximizing our profitability. We gather and transport natural gas, NGLs and propylene under fee-based contracts. Pipeline throughput volumes from existing wells connected to our pipelines will naturally decline over time as wells deplete. Accordingly, to maintain or increase throughput levels on these pipelines, we must continually obtain new supplies of natural gas. Our ability to maintain existing supplies of natural gas and NGLs and obtain new supplies are impacted by (1) the level of workovers or recompletions of existing

connected wells and successful drilling activity in areas currently dedicated to our pipelines and (2) our ability to compete for volumes from successful new wells in other areas. We regularly monitor producer activity in the areas served by the Acadian Gas pipeline system, and the areas served by South Texas NGL pipeline system and Enterprise Products Partners’ Shoup and Armstrong fractionation facilities. The throughput volumes of propylene on our Lou-Tex and Sabine pipelines are substantially dependent upon the quantities of propylene produced at third-party plants that have pipeline connections with our propylene pipelines.

Gross Operating Margin. We evaluate segment performance based on gross operating margin, which is a non-GAAP financial measure. 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 most directly comparable GAAP measure to total segment gross operating margin is operating income. Our gross operating margin should not be considered as an alternative to operating income.

We define total (or combined) segment gross operating margin as operating income before:


	•	depreciation, amortization and accretion expense;

	•	gains and losses on the sale of assets; and

	•	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 any intersegment and intrasegment transactions. Our combined revenues reflect the elimination of all material intercompany transactions.

We include equity earnings from Evangeline in our measurement of segment gross operating margin and operating income. This method of operation enables us to achieve favorable economies of scale relative to our level of investment and also lowers our exposure to business risks compared to the profile we would have on a stand-alone basis. Our equity investments are within the same industry as our combined operations; therefore, we believe treatment of earnings from our equity method investee as a component of gross operating margin and operating income is appropriate.

Gross operating margin should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Please read “Summary — Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.”


	•	the financial performance of our assets without regard to financing methods, capital structures or historical cost basis;

	•	the ability of our assets to generate cash sufficient to pay interest cost and support our indebtedness;

	•	our operating performance and return on capital as compared to those of other companies in the midstream energy industry, without regard to financing and capital structure; and

	•	the viability of projects and the overall rates of return on alternative investment opportunities.

Because EBITDA excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the EBITDA data presented in this prospectus may not be

comparable to similarly titled measures of other companies. The GAAP measure most directly comparable to EBITDA is net cash flows provided by operating activities.

EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. Please read “Summary — Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.”

Natural Gas Supply and Outlook

We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the United States, including Texas and Louisiana, as producers seek to increase their level of natural gas production. Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. A number of the areas in which we operate are experiencing significant drilling activity as a result of recent high natural gas prices, increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques.

While we anticipate continued high levels of exploration and production activities in a number of the areas in which we operate, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. We have no control over the level of drilling activity in the areas of our operations.

Factors Affecting Comparability of Future Results

You should read the discussion of our financial condition and results of operations in conjunction with our historical and pro forma financial statements included elsewhere in this prospectus. Our future results could differ materially from our historical results due to a variety of factors, including the following:

Partial Ownership of Operating Assets. After this offering, we will own 66% of the equity interests in the subsidiaries that hold our operating assets and affiliates of Enterprise Products Partners will continue to own the remaining 34%. The historical combined financial statements of Duncan Energy Partners Predecessor were prepared from Enterprise Products Partners’ separate historical accounting records related to our operating assets. Accordingly, the discussion that follows includes 100% of the results of operations for our operating assets, but in the future we will only have a 66% interest in those results.

No Historical Results for Our NGL Pipeline Services Segment. The discussion of our historical results that follows does not reflect any operations related to our NGL Pipeline Services segment, which includes a 223-mile pipeline, a 10-mile pipeline to be acquired from TEPPCO Partners for $8 million, and a 10-mile pipeline leased from TEPPCO Partners until completion during mid-2007 of a parallel 10-mile pipeline currently under construction by us. We acquired the 223-mile pipeline in August 2006, at which time the seller informed us that no discrete and separable financial information existed for the pipeline. In addition, the seller had previously utilized the pipeline for a different product and the pipeline was out of service when we acquired it. The 10-mile pipeline to be purchased from TEPPCO Partners was used as a feeder line for NGL products and operated by different management. We understand no financial statement information is available for this minor component asset. There is no meaningful financial data available regarding the prior use of these pipelines by the sellers that would be meaningful to our investors. In addition, such data, if available, would not assist investors in understanding either the evolution of the business (which is a new NGL transportation network) nor the track record of management (which will be different).

Increase in Outstanding Indebtedness. Historically, we have not had any consolidated indebtedness and, therefore, we have not had consolidated interest expense. We expect to borrow approximately $200 million under a new credit facility in connection with this offering, which amount will be paid to Enterprise Products

Partners in connection with its contribution of our operating assets to us. These additional borrowings are expected to increase interest expense by approximately $13.4 million per year assuming an interest rate of 6.5% and amortization of debt issuance costs.

Increased Storage Fees. In connection with this offering, we will increase certain storage fees charged to Enterprise Products Partners for use of Mont Belvieu Caverns. Historically, such intercompany charges were below market and eliminated in the consolidated revenues and costs and expenses of Enterprise Products Partners. Prospectively, such rates will be market-related. The pro forma increase in storage revenues is $6.2 million for the six months ended June 30, 2006 and $11.6 million for the year ended December 31, 2005.

Special Allocation of Measurement Gains and Losses. Storage well gains and losses occur when product movements into a storage well are different from those redelivered to customers. In general, such variations result from difficulties in precisely measuring significant volumes of liquids at varying flow rates and temperatures. It is expected that substantially all product delivered into storage will be withdrawn over time. A measurement loss in one period is expected to be offset by a measurement gain in a subsequent period, unless product is physically lost in a storage well due to problems with cavern integrity.

Historically, storage well measurement gains and losses, and associated reserve accounts, have been included in our financial statements. Operating costs and expenses reflect well loss accruals of $3.1 million, $0.6 million and $2.4 million for the years ended December 31, 2005, 2004 and 2003, respectively, and $0 and $1.9 million for the six months ended June 30, 2006 and 2005, respectively. At June 30, 2006, the financial statements of Duncan Energy Partners Predecessor included $0.8 million in a measurement gain and loss reserve account.

In addition, operating gains and losses due to measurement variances for product movements to and from storage wells relating primarily to pipeline and well connection activities are included in our financial statements. Many of our customer storage arrangements allow us to retain a small amount of liquid volumes to help offset any measurement losses. These variances are estimated and settled at current prices each reporting period as a net credit or charge to operating costs and expenses. We do not retain volumes in inventory. The net amounts for each of the years ended December 31, 2005, 2004 and 2003 were a $2.1 million charge, a $0.2 million credit and a $1.4 million credit, respectively, and a $1.4 million charge and a $0.7 million charge for the six months ended June 30, 2006 and 2005, respectively.

In connection with storage agreements for a variety of products entered into between Enterprise Products Partners and Mont Belvieu Caverns effective concurrently with the closing of this offering, Enterprise Products Partners will agree to the allocation of all measurement gains and losses relating to these products.

In addition, the limited liability company agreement for Mont Belvieu Caverns will specially allocate to Enterprise Products Partners any items of income and gain or loss and deduction relating to net measurement losses and measurement gains, including amounts that Mont Belvieu Caverns may retain or deduct as handling losses. Enterprise Products Partners will also be required to contribute cash to Mont Belvieu Caverns, or will be entitled to receive distributions from Mont Belvieu Caverns, based on the then-current net measurement gains or measurement losses. As a result, we will continue to record measurement gains and losses associated with the operation of our Mont Belvieu storage facility for parties other than Enterprise Products Partners after the closing date of this offering on a combined basis as operating costs and expenses. However, these measurement gains and losses should not affect our net income or have a significant impact on us with respect to our cash flows from operating activities and, accordingly, no reserve account will be established by us for measurement losses on our balance sheet.

We will be responsible for product losses attributable to cavern integrity events. During the three years ended December 31, 2005 and six months ended June 30, 2006, we did not experience any significant physical loss of product due to a loss of cavern integrity.

Decrease in Propylene Transportation Rates. The transportation rates that we receive for our Lou-Tex propylene pipeline and our Sabine propylene pipeline for periods after our initial public offering will be lower than our historical transportation rates. Historically, Enterprise Products Partners was the shipper of record, and we charged it the maximum tariff rate for using these assets. Enterprise Products Partners then contracted

with third parties to ship volumes on these pipelines under exchange agreements. In general, the revenues recognized by Enterprise Products Partners in connection with these exchange agreements were less than the maximum tariff rate it paid us. In connection with this offering, Enterprise Products Partners will assign its exchange agreements to us. Accordingly, the transportation rates we receive for use of our Lou-Tex propylene pipeline and Sabine propylene pipeline will be less than the historical rates that we received from Enterprise Products Partners. The pro forma reduction in revenues was $10.8 million for the six months ended June 30, 2006 and $18.4 million for the year ended December 31, 2005.

Additional General and Administrative Expenses. We expect to incur approximately $2.5 million in incremental general and administrative expenses as a result of becoming a publicly traded entity. These costs include fees associated with annual and quarterly reports to unitholders, tax returns and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, accounting and legal services. These costs also include estimated related party amounts payable to EPCO in connection with the administrative services agreement. For additional information regarding the administrative services agreement, please read “Certain Relationships and Related Party Transactions — Administrative Services Agreement.”

Results of Operations

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


							For the Six Months
	Year Ended December 31,						Ended June 30,
	2005		2004		2003		2006		2005

Revenues	$	953,397	$	748,931	$	668,234	$	503,791	$	400,029
Operating costs and expenses		909,044		685,544		609,774		478,586		377,779
General and administrative costs		4,483		5,442		6,138		1,735		2,436
Equity in income of unconsolidated affiliates		331		231		131		354		197
Operating income		40,201		58,176		52,453		23,824		20,011
Net income		39,087		58,124		52,454		23,816		20,011

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

Combined Revenues. Combined revenues for the first six months of 2006 were $503.8 million compared to $400 million for the first six months of 2005. The period-to-period increase in combined revenues is primarily due to a $99.1 million increase in revenues associated with natural gas marketing activities, which benefited from higher natural gas sales volumes and prices. The Henry Hub market price of natural gas averaged $7.91 per MMBtu for the first six months of 2006 versus $6.51 per MMBtu for the first six months of 2005. In addition, revenues from the NGL & Petrochemical Storage Services segment increased $4.8 million period-to-period primarily due to higher storage volumes.

Combined Costs and Expenses. Combined operating costs and expenses were $478.6 million for the first six months of 2006 compared to $377.8 million for the first six months of 2005. The period-to-period increase in costs and expenses is primarily due to increased natural gas marketing activities. General and administrative costs decreased $0.7 million period-to-period.

Segment Results. The following information highlights significant period-to-period variances in gross operating margin by business segment.

Gross operating margin from the NGL & Petrochemical Storage Services segment was $8.9 million for the first six months of 2006 compared to $5.7 million for the first six months of 2005. The $3.2 million increase in gross operating margin is primarily due to higher storage volumes period-to-period caused by increased activity among current customers.

Gross operating margin from the Natural Gas Pipelines & Services segment was $10.9 million for the first six months of 2006 versus $9.1 million for the first six months of 2005, an increase of $1.8 million. Natural gas transportation volumes increased to 789 Bbtu/d during the first six months of 2006 from 663 Bbtu/d during the same period in 2005. The effects of lower natural gas sales margins period-to-period were more than offset by the collection of a $2.3 million contingent asset related to a prior business acquisition during the first six months of 2006. Equity earnings from our investment in Evangeline increased $0.2 million period-to-period.

Gross operating margin from the Petrochemical Pipeline Services segment was $15.9 million for the first six months of 2006 versus $17.1 million for the first six months of 2005. Petrochemical transportation volumes were 35 MBPD during the first six months of 2006 versus 38 MBPD during the 2005 period. The $1.2 million decrease in gross operating margin is primarily due to lower transportation volumes and a lower average transportation fee charged on our Lou-Tex propylene pipeline during the first six months of 2006 relative to the first six months of 2005.

Comparison of Year Ended December 31, 2005 with Year Ended December 31, 2004

Combined Revenues. Combined revenues for 2005 were $953.4 million compared to $748.9 million for 2004. The year-to-year increase in combined revenues is primarily due to higher natural gas sales prices during 2005 relative to 2004, which accounted for a $208.2 million increase in combined revenues associated with natural gas marketing activities. The Henry Hub market price of natural gas averaged $8.64 per MMBtu during 2005 versus $6.13 per MMBtu during 2004.

Combined Costs and Expenses. Combined operating costs and expenses for 2005 were $909 million compared to $685.5 million for 2004. The year-to-year increase in costs and expenses is primarily due to an increase in the cost of sales associated with natural gas marketing activities. Such costs increased $213 million year-to-year as a result of higher natural gas prices. General and administrative costs decreased $1 million year-to-year.

Other Income (Expense), Net. The amount in 2005 relates to interest accrued on potential assessments related to a state sales tax dispute.

Segment Results. The following information highlights significant year-to-year variances in gross operating margin by business segment:

Gross operating margin from the NGL & Petrochemical Storage Services segment was $16.6 million for 2005 compared to $19.8 million for 2004. A $3.3 million increase in revenues for 2005 attributable to higher storage volumes was more than offset by higher operating expenses year-to-year. Operating expenses increased $6 million year-to-year primarily due to higher utility costs and higher measurement losses recognized in 2005.

Gross operating margin from the Natural Gas Pipelines & Services segment was $18.9 million for 2005 compared to $25.3 million for 2004. Natural gas transportation volumes were 640 Bbtu/d during 2005 compared to 645 Bbtu/d during 2004. Gross operating margin decreased $6.4 million year-to-year primarily due to lower margins on natural gas sales during 2005. Lower natural gas sales margins accounted for $4.8 million of the year-to-year decrease in gross operating margin. In addition, operating costs and expenses increased $1.7 million year-to-year primarily due to higher sales tax and pipeline integrity costs during 2005 as compared to 2004. Equity earnings from our investment in Evangeline increased $0.1 million year-to-year.

Gross operating margin from the Petrochemical Pipeline Services segment was $28.6 million for 2005 compared to $36.9 million for 2004. Petrochemical transportation volumes decreased to 33 MBPD during 2005 from 39 MBPD during 2004. Gross margin decreased $8.3 million year-to-year primarily due to reduced transportation volumes. Lower transportation volumes accounted for $6.8 million of the year-to-year decrease in gross operating margin. In addition, operating costs and expenses increased $1.1 million year-to-year primarily due to higher pipeline integrity costs during 2005 compared to 2004.

Cumulative Effect of Change in Accounting Principle. Net income for 2005 includes a $0.6 million non-cash charge for the cumulative effect of change in accounting principle related to asset retirement obligations. For additional information regarding this accounting change, please read “— Other Items” below.

Comparison of Year Ended December 31, 2004 with Year Ended December 31, 2003

Combined Revenues. Combined revenues were $748.9 million for 2004 compared to $668.2 million for 2003. The year-to-year increase is primarily due to higher natural gas sales prices during 2004 relative to 2003, which accounted for an $80.5 million increase in combined revenues associated with natural gas marketing activities. The Henry Hub market price of natural gas averaged $6.13 per MMBtu during 2004 versus $5.38 per MMBtu during 2003.

Combined Costs and Expenses. Combined operating costs and expenses were $685.5 million for 2004 compared to $609.8 million for 2003. The year-to-year increase in costs and expenses is primarily due to an increase in the cost of sales associated with natural gas marketing activities. Such costs increased $76.8 million year-to-year primarily due to higher natural gas prices. General and administrative costs decreased $0.7 million year-to-year.

Segment Results. The following information highlights significant year-to-year variances in gross operating margin by business segment:

Gross operating margin from the NGL & Petrochemical Storage Services segment was $19.8 million for 2004 and 2003. Operating costs and expenses were essentially unchanged period-to-period. A decrease of $1.0 million in net measurement losses in 2004 relative to 2003 was offset by a $1.1 million increase in repair and other maintenance costs in 2004.

Gross operating margin from the Natural Gas Pipelines & Services segment was $25.3 million for 2004 versus $18.3 million for 2003. Natural gas transportation volumes increased to 645 Bbtu/d during 2004 from 600 Bbtu/d during 2003. Gross operating margin increased $7 million year-to-year primarily due to improved margins on natural gas sales and higher natural gas transportation volumes. Gross operating margin for 2004 includes a $1.7 million benefit from the collection of a contingent asset related to a prior business acquisition. Equity earnings from our investment in Evangeline increased $0.1 million year-to-year.

Gross operating margin from the Petrochemical Pipeline Services segment was $36.9 million for 2004 compared to $38.4 million for 2003. Petrochemical transportation volumes were 39 MBPD during 2004 versus 40 MBPD during 2003. Gross operating margin from the Lou-Tex propylene pipeline decreased $1.5 million year-to-year as a result of reduced transportation volumes.

Liquidity and Capital Resources

Our primary cash requirements will be normal operating and general and administrative expenses, capital expenditures, business acquisitions, distributions to partners and debt service. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows and borrowings under a new commercial bank credit facility. 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 the new commercial bank credit facility, and the issuance of additional debt or equity securities. We expect to fund cash distributions to partners primarily with operating cash flows. Debt service requirements are expected to be funded by operating cash flows or refinancing arrangements.

Duncan Energy Partners Predecessor Cash Flow

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 read the Statements of Combined Cash Flows included elsewhere in this prospectus.


							For the Six Months
	For Year Ended December 31,						Ended June 30,
	2005		2004		2003		2006			2005

Net cash provided by operating activities	$	40,568	$	79,463	$	64,732	$	26,876		$	23,676
Net cash used in investing activities		19,503		6,931		340		33,227			9,409
Net cash used in (provided by) financing activities		21,065		72,532		64,392		(6,351	)		14,267

We have operated within the Enterprise Products Partners’ cash management program for all periods presented. For purposes of presentation in the Statements of Combined Cash Flows, cash flows from financing activities represent transfers of excess cash from us to Enterprise Products Partners equal to cash provided by operations less cash used in investing activities. Such transfers of excess cash are shown as distributions to owners in the Statements of Combined Owners’ Net Investment. Conversely, if cash used in investing activities is greater than cash provided by operations, then a deemed contribution by owners is presented. As a result, the combined financial statements do not present cash balances for any of the periods presented.

Due to the foregoing method of presentation, our owners were deemed to have made net cash contributions totaling $6.4 million during the first six months of 2006 and been paid $14.3 million in net cash distributions during the first six months of 2005.

Cash used in investing activities primarily represents expenditures for capital projects. Cash used in financing activities generally consists of contributions from and distributions to owners.

The following information highlights the significant period-to-period 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 by operating activities was $26.9 million for the first six months of 2006 compared to $23.7 million for the first six months of 2005. The $3.2 million increase in net cash provided by operating activities is primarily due to higher earnings for the first six months of 2006 relative to the same period in 2005 and the timing of cash receipts from sales and cash payments for purchases and other expenses between periods. For information regarding changes in revenues and costs and expenses between the two six month periods, please read “— Results of Operations” above.

Investing activities. Cash used in investing activities was $33.2 million for the first six months of 2006 compared to $9.4 million for the first six months of 2005. The $23.8 million increase in cash used in investing activities is primarily due to an expansion of our Mont Belvieu, Texas storage complex. The expansion includes the drilling of two new brine production wells and the construction of two above-ground brine storage reservoirs.

Financing activities. Net cash provided by financing activities was $6.4 million for the first six months of 2006 compared to net cash used of $14.3 million for the first six months of 2005.

Comparison of Year Ended December 31, 2005 with Year Ended December 31, 2004

Operating activities. Net cash provided by operating activities was $40.6 million for 2005 compared to $79.5 million for 2004. The $38.9 million decrease in net cash provided by operating activities is primarily due to lower earnings in 2005 relative to 2004 and the timing of cash receipts from sales and cash payments for purchases and other expenses between periods. For information regarding changes in revenues and costs and expenses between the two years, please read “— Results of Operations” above.

Investing activities. Cash used in investing activities was $19.5 million for 2005 compared to $6.9 million for 2004. The $12.6 million increase in cash used in investing activities was primarily due to the expansion of brine production and storage reservoirs at our Mont Belvieu storage complex.

Financing activities. Net cash distributions to owners were $21.1 million for 2005 compared to $72.5 million for 2004. The change in cash distributions results from a decrease in cash provided by operating activities in 2005 combined with an increase in cash used for capital expenditures in 2005.

Comparison of Year Ended December 31, 2004 with Year Ended December 31, 2003

Operating activities. Net cash provided by operating activities was $79.4 million for 2004 compared to $64.7 million for 2003. The $14.7 million increase in net cash provided by operating activities is due to higher earnings in 2004 relative to 2003 and the timing of cash receipts from sales and cash payments for purchases and other expenses between periods. For information regarding changes in revenues and costs and expenses between the two years, please read “— Results of Operations” above.

Investing activities. Cash used in investing activities was $6.9 million for 2004 compared to $0.3 million for 2003. In January 2002, we acquired a number of storage wells from a third-party seller. The purchase price we paid included four wells that were later determined not to be usable for storage. We received a $10 million refund of the purchase price from the seller in 2003, which is reflected as “Cash refund from prior business combination” on our Statements of Combined Cash Flows.

Financing activities. Net cash distributions to owners were $72.5 million for 2004 compared to $64.4 million for 2003. The change in cash distributions results primarily from a $14.7 million increase in cash provided by operating activities in 2004 partially offset by a $6.6 increase in cash used in investing activities. As noted above, cash used in investing activities for 2003 includes a $10 million refund, related to an asset acquisition (a benefit).

Capital Requirements

General. The midstream energy business can be capital intensive, requiring significant investment to maintain and upgrade existing operations. For example, 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. This federal agency has issued safety regulations containing requirements for the development of integrity management programs for hazardous liquid pipelines (which include NGL and petrochemical pipelines) and natural gas pipelines. In general, these regulations require companies to assess the condition of their pipelines in certain high consequence areas (as defined by the regulation) and to perform any necessary repairs. In connection with the regulations for hazardous liquid pipelines, we developed a pipeline integrity management program in 2002. In connection with the regulations for natural gas pipelines, we developed a pipeline integrity management program in 2004.

The following table summarizes our expenditures for pipeline integrity costs for the periods indicated (dollars in thousands):


							For the Six Months
	For Year Ended December 31,						Ended June 30,
	2005		2004		2003		2006		2005

Recorded in operating costs and expenses	$	1,927	$	707	$	25	$	1,556	$	547
Recorded in capital expenditures		1,750		1				3,525		267

Total	$	3,677	$	708	$	25	$	5,081	$	814

We expect our net cash outlay for pipeline integrity program expenditures to approximate $4.2 million during the remainder of 2006.

Our capital requirements have consisted primarily of, and we anticipate will continue to consist of, the following:


	•	sustaining capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows (such as pipeline integrity costs); and

	•	expansion capital expenditures such as those to acquire additional assets to grow our business, to expand and upgrade gathering systems and processing plants and to construct or acquire similar systems or facilities.

During the first six months of 2006, our capital expenditures, including sustaining and expansion capital expenditures, totaled $33.2 million. We have budgeted sustaining capital expenditures of $5.9 million for the year ending December 31, 2007. We expect that the costs to complete the planned expansion of the South Texas NGL pipeline after the closing of this offering will be approximately $30.9 million, of which our 66% share will be approximately $20.4 million. We expect to use cash on hand from the proceeds of this offering to fund our share of the planned expansion costs and Enterprise Products Partners will make a capital contribution to South Texas NGL for its 34% share of the planned expansion costs.

We are evaluating several expansion projects at our Mont Belvieu facilities. The projects currently contemplated may be commenced during 2007 in the range of $25 to $75 million. Additional expenditures of up to $200 million may be made during 2008 and 2009. Pursuant to the Mont Belvieu Caverns limited liability company agreement, Enterprise Products OLP may, in its sole discretion, fund a portion of any costs related to these projects. We cannot assure you that we will pursue any expansion projects, but if we do, we expect to finance any such projects through borrowings under our credit facility, the issuance of debt or additional equity, or contributions from Enterprise Products OLP. For a further description of our agreements with Enterprise Products Partners relating to potential expansion opportunities, please read “Business — NGL & Petrochemical Storage Services Segment — Mont Belvieu Expansion Opportunities,” and “Certain Relationships and Related Party Transactions — Mont Belvieu Caverns Limited Liability Company Agreement — Mont Belvieu Caverns Expansion Capital Agreements.”

New Credit Facility

Concurrently with the closing of this offering, we expect to enter into a new $ million revolving credit facility, which will mature on , 2012. The new credit agreement will be available to fund working capital, make acquisitions and provide payment for general partnership purposes.

We may prepay all loans at any time without penalty, subject to the reimbursement of lender breakage costs in the case of prepayment of LIBOR borrowings. Indebtedness under the new credit agreement will bear interest, at our option, at the time of each borrowing at:


	•	the greater of (a) the interest rate per annum publicly announced by as its prime rate or (b) the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published by the Federal Reserve Bank of New York in either case plus an applicable margin of %; or

	•	LIBOR plus an applicable margin of %.

We expect that the new credit agreement will require us to maintain a leverage ratio (the ratio of our consolidated indebtedness to our consolidated EBITDA, in each case as will be defined by the credit agreement) of not more than to 1.0 and on a temporary basis for not more than three consecutive quarters following the consummation of certain acquisitions, not more than to 1.0. We expect that the new credit agreement will require us to maintain an interest coverage ratio (the ratio of our consolidated EBITDA to our consolidated interest expense, in each case as will be defined by the new credit agreement) of

not less than to 1.0 determined as of the last day of each quarter for the four-quarter period ending on the date of determination.

Our new credit facility is anticipated to contain various operating and financial covenants, including those restricting or limiting our ability, and the ability of certain of our subsidiaries, to:


	•	make distributions if any default or event of default occurs;

	•	incur additional indebtedness or guarantee other indebtedness;

	•	grant liens or make certain negative pledges;

	•	make certain loans or investments;

	•	make any material change to the nature of our business, including consolidations, liquidations and dissolutions; or

	•	enter into a merger, consolidation, sale and leaseback transaction or sale of assets.

If an event of default exists under the new credit agreement, the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. We expect that each of the following could be an event of default under the new credit agreement:


	•	failure to pay any principal when due or any interest or fees within five business days of the due date;

	•	failure to perform or otherwise comply with the covenants in the credit agreement;

	•	failure of any representation or warranty to be true and correct in any material respect;

	•	failure to pay any other material debt;

	•	a change of control; and

	•	other customary defaults, including specified bankruptcy or insolvency events, the Employee Retirement Income Security Act of 1974, or ERISA, violations, and judgment defaults.

After this offering, we expect to have borrowings of approximately $200 million and letters of credit of $ million outstanding under this facility, with $ million available under this credit facility.

Our entry into the new credit facility is subject to a number of conditions, including no material adverse change in our business and the negotiation, execution and delivery of definitive documentation.

Contractual Obligations

The following table summarizes our significant contractual obligations at December 31, 2005.


	Payment or Settlement Due by Period
			Less Than		1-3		3-5		More Than
Contractual Obligations(1)	Total		1 Year		Years		Years		5 Years
			(2006)		(2007-2008)		(2009-2010)		Beyond 2010

Operating leases:
Underground natural gas storage cavern	$	3,276	$	468	$	936	$	936	$	936
Right-of-way agreements	$	533	$	79	$	159	$	26	$	269
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	1,214,413	$	173,352	$	347,179	$	346,704	$	347,178
Other	$	5,983	$	1,710	$	3,425	$	848
Underlying major volume commitments:
Natural gas (in Bbtus)		102,280		14,600		29,240		29,200		29,240
Capital expenditure commitments	$	616	$	616
Other long-term liabilities	$	608							$	608

Total	$	1,225,429	$	176,225	$	351,699	$	348,514	$	348,991


(1)		The contractual obligations in this table reflect the obligations of our subsidiaries on a total consolidated basis even though we own less than a 100% equity interest in our operating subsidiaries.

Scheduled maturities of long-term debt. The foregoing table does not reflect approximately $200 million of borrowings that we expect to make under our new credit facility that we will enter into at or prior to the closing of this offering.

Estimated cash payments for interest. The foregoing table does not reflect any estimated cash payments for interest on expected initial borrowings of approximately $200 million under our new credit facility that are expected to be made under variable interest rates.

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

Our Natural Gas Pipelines & Services segment leases an underground natural gas storage cavern that is integral to its operations. The primary use of this cavern is to store natural gas held-for-sale by us. The current term of the cavern lease expires in December 2012. The term of this contract does not provide for an additional renewal period, but it requires the lessor to enter into diligent negotiations with us under similar terms and conditions if we wish to extend the lease agreement beyond December 2012.

In addition, our pipeline operations have entered into leases for land held pursuant to right-of-way agreements. Our significant right-of-way agreements have original terms that range from five to 50 years and include renewal options that could extend the agreements for up to an additional 25 years. Our rental payments are generally at fixed rates, as specified in the individual contracts, and may be subject to escalation provisions for inflation and other market-determined factors.

Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments, if any, are expensed as incurred. In general, we are required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets attributable to our operations

are charged to expense as incurred. We have not made any significant leasehold improvements during the periods presented. Lease expense included in operating income was $1.2 million for each of the years ended December 31, 2005, 2004 and 2003.

Purchase Obligations. We define purchase obligations as agreements to purchase goods or services that are enforceable and legally binding (unconditional) on us that specify all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions.

Our Natural Gas Pipelines & Services segment has a product purchase commitment for the purchase of natural gas in Louisiana from a third party. This purchase agreement expires in January 2013. Our purchase price under this contract approximates the market price of natural gas at the time we take delivery of the volumes. The preceding table shows the volume we are committed to purchase and an estimate of our future payment obligations for the periods indicated. Our estimated future payment obligations are based on the contractual price at December 31, 2005 applied to all future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery.

At December 31, 2005, we do not have any product purchase commitments with fixed or minimum pricing provisions having remaining terms in excess of one year.

We also have short-term payment obligations relating to capital projects we have initiated. These commitments represent unconditional payment obligations that we have agreed to pay vendors for services to be rendered or products to be delivered in connection with our capital spending programs. The preceding table shows these capital project commitments for the periods indicated.

In August 2006, Enterprise Products Partners purchased 223 miles of NGL pipelines extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The total purchase price for this asset was approximately $97.7 million in cash. This pipeline system will be owned by South Texas NGL (along with others to be constructed or acquired) and will be used to transport NGLs from two Enterprise Products Partners’ facilities to Mont Belvieu, Texas. The total estimated cost to acquire and construct the additional pipelines that will complete this system is $68.6 million. We expect that South Texas NGL will make capital expenditures of $37.7 million, including approximately $8 million to acquire a 10-mile pipeline from an affiliate, TEPPCO Partners, to make this pipeline system operational prior to the closing of this offering. We expect that it will cost approximately $30.9 million to complete planned expansions of the South Texas NGL pipeline after the closing of this offering, of which our 66% share will be approximately $20.4 million. Following this offering, we expect to use cash on hand from the proceeds of this offering to fund our share of the planned expansion costs. The preceding contractual obligations table does not include these capital expenditures entered into after December 31, 2005.

Other Long-Term Liabilities. We have recorded long-term liabilities on our combined balance sheet reflecting amounts we expect to pay in future periods beyond one year. These liabilities primarily represent the present value of our asset retirement obligations. Amounts shown in the preceding table represent our best estimate as to the timing of settlements based on information currently available.

Off-Balance Sheet Arrangements

At June 30, 2006 and December 31, 2005, long-term debt for Evangeline consisted of:


	•	$23.2 million in principal amount of 9.9% fixed interest rate senior secured notes due December 2010 (the “Series B” notes); and

	•	a $7.5 million subordinated note payable to Evangeline Northwest Corporation (the “ENC Note”).

The Series B notes are collateralized by the following:


	•	Evangeline’s property, plant and equipment;


	•	proceeds from Evangeline’s Entergy Louisiana natural gas sales contract; and

	•	a debt service reserve requirement.

Scheduled principal repayments on the Series B notes are $5 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. The trust indenture governing the Series B notes contains covenants such as requirements to maintain certain financial ratios. Evangeline was in compliance with such covenants during the periods presented.

Evangeline incurred the ENC Note obligations in connection with its acquisition of the Entergy natural gas sales contract in 1991. The ENC Note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B note holders are either fully cash secured through debt service accounts or have been completely repaid. Variable rate interest accrues on the subordinated note at a LIBOR rate plus 0.5%. Variable interest rates charged on this note at December 31, 2005 and 2004 were 4.23% and 1.83%, respectively.

Except for the foregoing, we have no off-balance sheet arrangements that have or are reasonably expected to have a material current or future effect on our financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the three-year period ended December 31, 2005 or the first six months of 2006. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenues and costs are influenced to a greater extent by specific price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees and through escalation provisions in specific contracts.

Seasonality

For a discussion of seasonality in each of our business segments, please read the description of each such segment contained in “Business” below.

Critical Accounting Policies and Estimates

In our financial reporting process, we employ methods, estimates and assumptions that will 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. The following is a description of 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. Some of these circumstances include changes in laws and regulations relating to restoration and abandonment requirements; changes in expected costs for dismantlement, restoration and abandonment as a result of changes, or expected changes, in labor, materials and other related costs associated with these activities; changes in the useful life of an asset based on the actual known life of

similar assets, changes in technology, or other factors; and changes in expected salvage proceeds as a result of a change, or expected change in the salvage market.

At June 30, 2006 and December 31, 2005, the net book value of our property, plant and equipment was $539.9 million and $512.2 million, respectively. We recorded $19.2 million, $18.1 million and $17.6 million in depreciation expense during the years ended December 31, 2005, 2004 and 2003, respectively. Depreciation expense was $10.0 million and $9.3 million for the six months ended June 30, 2006 and 2005, respectively.

Measuring recoverability of long-lived assets and equity method investments

In general, long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes might be production declines that are not replaced by new discoveries or long-term decreases in the demand or price of natural gas, oil or NGLs. Long-lived assets with recorded values that are not expected to be recovered through expected future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the existing asset. Our estimates of such undiscounted cash flows are based on a number of assumptions including anticipated operating margins and volumes; estimated useful life of the asset or asset group; and estimated salvage values. An impairment charge would be recorded for the excess of a long-lived asset’s carrying value over its estimated fair value. Fair value of a long-lived asset is estimated through appropriate valuation techniques, which consider quoted market prices, replacement cost estimates and probability-weighted discounted cash flows. We did not recognize any asset impairment charges during the years ended December 31, 2005, 2004 or 2003 or six months ended June 30, 2006.

Equity method investments are evaluated for impairment whenever events or changes in circumstances indicate that there is a possible loss in value of the investment other than a temporary decline. Examples of such events include sustained operating losses by the investee or long-term negative changes in the investee’s industry. The carrying value of an equity method investment is not recoverable if it exceeds the sum of the discounted estimated cash flows expected to be derived from the investment. This estimate of discounted cash flows is based on a number of assumptions including discount rates; probabilities assigned to different cash flow scenarios; anticipated margins and volumes and estimated useful life of the investment. A significant change in these underlying assumptions could result in our recording an impairment charge. We did not recognize any impairment charges related to our Evangeline affiliate during the years ended December 31, 2005, 2004 or 2003 or six months ended June 30, 2006.

Amortization methods and estimated useful lives of qualifying intangible assets

The specific, identifiable intangible assets of a business enterprise depend largely upon the nature of its operations. Intangible assets include, but are not limited to, patents, trademarks, trade names, contracts, customer relationships and non-compete agreements. The method used to value each intangible asset varies depending upon the nature of the intangible asset, the business in which it is utilized, and the economic returns it is generating or is expected to generate.

If our underlying assumptions regarding the estimated useful life of an intangible asset change, then the amortization period for such asset would be adjusted accordingly. Additionally, if we determine that an intangible asset’s unamortized cost may not be recoverable due to impairment, we may be required to reduce the carrying value and the subsequent useful life of the asset. Any such write-down of the value and unfavorable change in the useful life of an intangible asset would increase operating costs and expenses at that time.

Our intangible assets consist primarily of renewable storage contracts with various customers that we acquired in connection with the purchase of storage caverns from a third party in January 2002. Due to the renewable nature of these contracts, we amortize them on a straight-line basis over a 35-year period, which is the estimated remaining economic life of the storage assets to which they relate.

At June 30, 2006 and December 31, 2005, the carrying value of our intangible asset portfolio was $7.1 million and $7.2 million, respectively. We recorded $0.2 million in amortization expense associated with our intangible assets during each of the years 2005, 2004 and 2003.

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

In general, we recognize revenue from our customers when all of the following criteria are met:


	•	persuasive evidence of an exchange arrangement exists;

	•	delivery has occurred or services have been rendered;

	•	the buyer’s price is fixed or determinable; and

	•	collectibility is reasonably assured.

When sales contracts are settled (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed), we record any necessary allowance for doubtful accounts.

We make estimates for certain revenue and expense items due to time constraints on the financial accounting and reporting process. At times, we must estimate revenues from a customer before we actually bill the customer or accrue an expense we incur before physically receiving a vendor’s invoice. Such estimates reverse in the following period and are offset by our recording the actual customer billing and vendor invoice amounts. If the basis of our estimates proves to be substantially incorrect, it could result in material adjustments in results of operations between periods.

Natural gas imbalances

Natural gas imbalances result when a customer injects more or less gas into a pipeline than it withdraws. The values of our imbalance receivables and payables are based on natural gas prices during the month such imbalances are created.

At December 31, 2005 and 2004, our imbalance receivables were $1.6 million and $1.8 million, respectively, and are reflected as a component of “Accounts receivable — trade” on our Combined Balance Sheets. At December 31, 2005 and 2004, our imbalance payable was $2.9 million and $0.5 million respectively, and is reflected as a component of “Accrued gas payables” on our Combined Balance Sheets. At June 30, 2006, our imbalance receivable was $3.4 million and our imbalance payable was $0.6 million.

Storage gains and losses

Storage well gains and losses occur when product movements into a storage well are different than those redelivered to customers. In general, such variations result from difficulties in precisely measuring significant volumes of liquids at varying flow rates and temperatures. It is expected that substantially all product delivered into a storage will be withdrawn over time. A measurement loss in one period is expected to be offset by a measurement gain in a subsequent period, unless product is physically lost in a storage well due to problems with cavern integrity. We did not experience any significant net losses resulting from problems with cavern integrity during the three years ended December 31, 2005 or for the six-month period ended June 30, 2006.

Since we expect that storage well gains and losses will approximate each other over time, we historically charged storage well gains or losses to a storage imbalance account during the month such imbalances are created based on current pricing. The reserve was increased by measurement gains and loss accruals and decreased by measurement losses. On an annual basis, the storage imbalance reserve account was reviewed for reasonableness based on historical storage well measurement gains and losses and adjusted accordingly through a charge to earnings. At December 31, 2005 and 2004, our storage imbalance account was $4.5 million and $3.5 million. At June 30, 2006, our storage imbalance was $0.8 million. Net measurement losses of $2.0 million, $2.2 million and $1.5 million were charged to the reserve during the years ended December 31, 2005, 2004 and 2003, respectively, and $3.7 and $1.9 million for the six months ended June 30, 2006 and 2005, respectively. Operating costs and expenses reflect well loss accruals of $3.1 million, $0.6 million and

$2.4 million for the years ended December 31, 2005, 2004 and 2003, respectively, and $0 and $1.9 million for the six months ended June 30, 2006 and 2005, respectively.

In addition, operating gains and losses due to measurement variances for product movements to and from storage wells relating primarily to pipeline and well connection activities are included in our financial statements. Many of our customer storage arrangements allow us to retain a small amount of liquid volumes to help offset any measurement losses. These variances are estimated and settled at current prices each reporting period as a net credit or charge to operating costs and expenses. We do not retain volumes in inventory. The net amounts for each of the years ended December 31, 2005, 2004 and 2003 were a $2.1 million charge, $0.2 million credit and $1.4 million credit, respectively, and a $1.4 million charge and a $0.7 million charge for the six months ended June 30, 2006 and 2005, respectively.

In connection with storage agreements for a variety of products entered into between Enterprise Products Partners and Mont Belvieu Caverns effective concurrently with the closing of this offering, Enterprise Products Partners will agree to the allocation of all storage well measurement gains and losses relating to these products.

In addition, the limited liability company agreement for Mont Belvieu Caverns will specially allocate to Enterprise Products Partners any items of income and gain or loss and deduction relating to measurement losses and measurement gains, including amounts that Mont Belvieu Caverns may retain or deduct as handling losses. Enterprise Products Partners will also be required to contribute cash to Mont Belvieu Caverns, or will be entitled to receive distributions from Mont Belvieu Caverns, based on the then-current net measurement gains or measurement losses. As a result, we will continue to record measurement gains and losses associated with the operation of our Mont Belvieu storage facility for parties other than Enterprise Products Partners after the closing date of this offering on a consolidated basis as operating costs and expenses. However, these measurement gains and losses should not affect our net income or have a significant impact on us with respect to our cash flows from operating activities and, accordingly, no reserve account will be established by us for measurement losses on our balance sheet.

Recent Accounting Developments

Emerging Issues Task Force (“EITF”) 04-13, “Accounting for Purchases and Sales of Inventory With the Same Counterparty.” This accounting guidance requires that two or more inventory transactions with the same counterparty be viewed as a single non-monetary 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 combined 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.

Financial Accounting Standards Board Interpretation (“FIN”) No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of SFAS 109, Accounting for Income Taxes.” FIN 48 provides that the tax effects of an uncertain tax position should be recognized in a company’s financial statements if the position taken by the entity is more likely than not sustainable, if it were to be examined by an appropriate taxing authority, based on technical merit. After determining a tax position meets such criteria, the amount of benefit to be recognized should be the largest amount of benefit that has more than a 50 percent chance of being realized upon settlement. The provisions of FIN 48 are not material to our financial statements.

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.

SFAS 157, “Fair Value Measurements.” This accounting standard defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. SFAS 157 applies only to fair-value measurements that are already required or permitted by other accounting standards and is expected to increase the consistency of those measurements. The statement emphasizes that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Companies will be required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop the measurements, and the effect of certain of the measurements on earnings (or changes in net assets) for the period. SFAS 157 is effective for fiscal years beginning after December 15, 2007 and we will be required to adopt SFAS 157 as of January 1, 2008. We are currently evaluating the impact of adopting SFAS 157 on our financial position, results of operations, and cash flows.

Staff Accounting Bulletin (“SAB”) No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements.” SAB 108 addresses how the effects of prior-year uncorrected misstatements should be considered when quantifying misstatements in current-year financial statements. The SAB requires registrants to quantify misstatements using both the balance-sheet and income-statement approaches and to evaluate whether either approach results in quantifying an error that is material in light of relevant quantitative and qualitative factors. When the effect of initial adoption is determined to be material, SAB 108 allows registrants to record that effect as a cumulative-effect adjustment to beginning-of-year retained earnings. The requirements are effective for annual financial statements covering the first fiscal year ending after November 15, 2006. Additionally, the nature and amount of each individual error being corrected through the cumulative-effect adjustment, when and how each error arose, and the fact that the errors had previously been considered immaterial is required to be disclosed. We are required to adopt SAB 108 for our current fiscal year ending December 31, 2006. We do not expect the adoption of SAB 108 to have a material impact on our financial statements.

Related Party Transactions

We have an extensive and ongoing business relationships with EPCO and Enterprise Products Partners and each of their affiliates, including the following:


	•	Enterprise Products Partners. Enterprise Products Partners will assign to us all of the exchange agreements with the customers of our Sabine and Lou-Tex pipelines but will remain jointly and severally liable on these agreements. We also provide underground storage services to Enterprise Products Partners and its affiliates to store NGLs and petrochemicals. Upon the completion of our offering, we expect that certain terms of the related party storage contracts between us and Enterprise Products Partners will change, including (1) a reduction in transportation rates on our Lou-Tex and Sabine pipelines, (2) an increase in underground storage fees and (3) the allocation to Enterprise Products Partners of all storage measurement gains and losses relating to its products. In addition, the limited liability company agreement for Mont Belvieu Caverns will specially allocate to Enterprise Products Partners measurement gains and losses to Enterprise Products Partners, and contain related contribution and distribution provisions. Enterprise Products Partners will also remain jointly and severally liable for certain contracts with third parties that it will assign to us. Concurrently with the


		closing of this offering, we will enter into an omnibus agreement with Enterprise Products Partners pursuant to which Enterprise Products Partners will agree to (i) indemnify us for certain environmental liabilities, tax liabilities and title and right-of-way defects occurring or existing before the closing of this offering and (ii) reimburse us for our 66% share of excess construction costs, if any, above our current estimated cost to complete planned expansions on the South Texas NGL pipeline.


	•	TEPPCO Partners. We currently provide underground storage services to a subsidiary of TEPPCO Partners.

	•	EPCO. We have no employees. Prior to the closing of this offering, we will become party to the administrative services agreement with EPCO. Under this agreement, EPCO will provide general administrative, management, engineering and operating services as may be necessary to operate our businesses, properties and assets (in accordance with prudent industry practices). We will be required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including EPCO expenses reasonably allocated to us). The administrative services agreement also contains agreements relating to business opportunities.

	•	Evangeline. We sell natural gas to Evangeline, which, in turn, uses such natural gas to satisfy its sales commitments to Entergy Louisiana. In addition, we also have a service agreement with Evangeline whereby we provide Evangeline with construction, operations, maintenance and administrative support related to its pipeline system.

For more information, please read “Certain Relationships and Related Party Transactions” and Note 6 of the combined financial statements of the Duncan Energy Partners Predecessor.

Other Items

Provision for income taxes — Texas Margin Tax. All of our operating subsidiaries are organized as pass-through entities for income tax purposes. As a result, the owners of such entities are responsible for federal income taxes on their share of each entity’s taxable income.

In May 2006, the State of Texas substantially revised its existing state franchise tax. The revised tax (the “Texas Margin Tax”) becomes effective for franchise tax reports due on or after January 1, 2008. In general, legal entities that conduct business in Texas and benefit from limited liability protection are subject to the Texas Margin Tax. As a result of the change in tax law, we believe that our tax status in the State of Texas will change such that we will become subject to the Texas Margin Tax. We recorded an estimated deferred tax liability of approximately $21 thousand for the Texas Margin Tax in June 2006, with an offsetting expense shown as provision for income taxes.

Cumulative effect of changes in accounting principles. We recorded a cumulative effect of a change in accounting principle of $0.6 million in connection with our implementation of FASB Interpretation No. 47, “Accounting for Conditional Asset Requirement Obligations” (“FIN 47”) in December 2005, which represents the depreciation and accretion expense we would have recognized had we recorded these conditional asset retirement obligations when incurred. The pro forma effects of our adoption of FIN 47 are not presented due to the immaterial nature of these amounts to our financial statements. Based on information currently available, we estimate that annual accretion expense will approximate $0.1 million for each of the years 2006 through 2010.

Certain key employees of EPCO who allocate a portion of their time to our affairs participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of restricted units of Enterprise Products Partners and limited partner interests in EPE Unit L.P., a Delaware limited partnership. Prior to January 1, 2006, EPCO accounted for these awards using the provisions of Accounting Principles Board Opinion 25, “Accounting for Stock Issued to Employees.” On January 1, 2006, EPCO adopted Statement of Financial Accounting Standards (“SFAS”) 123(R), “Accounting for Stock-Based Compensation,” to account for such awards. Upon adoption of this accounting standard, we recognized a cumulative effect of change in

accounting principle of $9 thousand (a benefit). Such awards are immaterial to our combined financial position, results of operations and cash flows.

Quantitative and Qualitative Disclosures about Market Risk

General. We use financial instruments in our Natural Gas Pipelines & Services segment to secure certain fixed price natural gas sales contracts (referred to as “customer fixed-price arrangements”). We also enter into a limited number of cash flow hedges in connection with such business. We recognize such instruments on the balance sheet as assets or liabilities based on an instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. Changes in fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met.

To qualify as a hedge, the item to be hedged must expose us to commodity price risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We formally designate such financial instruments as hedges and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness is immediately recognized in earnings. Our customer fixed-price arrangements do not qualify for hedge accounting under SFAS 133; therefore, these instruments are accounted for using a mark-to-market approach each reporting period.

If a financial instrument meets the criteria of a cash flow hedge, gains and losses from the instrument are recorded in other comprehensive income. Gains and losses on cash flow hedges are reclassified from other comprehensive income to earnings when the forecasted transaction occurs or, as appropriate, over the economic life of the underlying asset. If the financial instrument meets the criteria of a fair value hedge, gains and losses from the instrument will be recorded on the income statement to offset corresponding losses and gains of the hedged item. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.

Commodity financial instrument portfolio. In addition to its natural gas transportation business, our Natural Gas Pipelines & Services segment engages in the purchase and sale of natural gas to third party customers in the Louisiana area. The price of natural gas fluctuates in response to changes in supply, market uncertainty, and a variety of additional factors that are beyond our control. We may use commodity financial instruments such as futures, swaps and forward contracts to mitigate such risks. In general, the types of risks we attempt to hedge are those related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices. The commodity financial instruments we utilize may be settled in cash or with another financial instrument. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.

Our Natural Gas Pipelines & Services segment enters into a small number of cash flow hedges in connection with its purchase of natural gas held-for-sale. In addition, our Natural Gas Pipelines & Services segment enters into a limited number of offsetting financial instruments that effectively fix the price of natural gas for certain of its customers. Historically, the use of commodity financial instruments was governed by policies established by the general partner of Enterprise Products Partners. The objective of this policy was to assist us in achieving its profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by the general partner. In general, we may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to its commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months.

The general partner of Enterprise Products Partners monitored the hedging strategies associated with the physical and financial risks of our Natural Gas Pipelines & Services segment (such as those mentioned previously), approved specific activities subject to the policy (including authorized products, instruments and markets) and established specific guidelines and procedures for implementing and ensuring compliance with the policy. Our general partner will continue such policies in the future.

Due to the limited number and nature of the financial instruments utilized by us, the effect on the portfolio of a hypothetical 10% movement in the underlying quoted market prices of natural gas is negligible at June 30, 2006 and December 31, 2005 and 2004. The fair value of our commodity financial instrument portfolio was a negligible amount at June 30, 2006, a liability of $0.1 million at December 31, 2005, and a liability of $0.3 million at December 31, 2004.

We recorded losses of $0.2 million and $0.8 million related to our commodity financial instruments for the years ended December 31, 2005 and 2003, respectively. In 2004, we recorded a gain of $0.2 million from our commodity financial instruments. We recorded $0.3 million of expense related to our commodity financial instruments during the six months ended June 30, 2006. We recorded nominal amounts of expense related to this portfolio during the six months ended June 30, 2005.

Product purchase commitments. Our Natural Gas Pipelines & Services segment has a long-term natural gas purchase contract with a third party. This purchase agreement expires in January 2013. Our purchase price under this contract approximates the market price of natural gas at the time we take delivery of the volumes. For additional information regarding our commitments, please read “— Contractual Obligations” above.

BUSINESS

Our Partnership

We are a Delaware limited partnership formed by Enterprise Products Partners in September 2006 to own, operate and acquire a diversified portfolio of midstream energy assets. We are engaged in the business of gathering, transporting, marketing and storing natural gas and transporting and storing NGLs and petrochemicals. Our assets were previously owned by Enterprise Products Partners and are part of its integrated midstream energy asset network or value chain, which includes natural gas gathering, processing, transportation and storage; NGL fractionation (or separation), transportation, storage and import and export terminaling; crude oil transportation; and offshore production platform services. After this offering, we will own 66% of the equity interests in the subsidiaries that hold our operating assets and affiliates of Enterprise Products Partners will continue to own the remaining 34%. We believe our relationship with Enterprise Products Partners will enable us to maintain stable cash flows and optimize our scale, strategic location and pipeline connections.

Our operations are organized into the following four business segments:


	•	NGL & Petrochemical Storage Services. Our NGL & Petrochemical Storage Services segment consists of 33 salt dome caverns located in Mont Belvieu, Texas, with an underground storage capacity of approximately 100 MMBbls, and certain related assets. These assets receive, store and deliver NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States.

	•	Natural Gas Pipelines & Services. Our Natural Gas Pipelines & Services segment consists of the Acadian Gas system, which is an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. In the aggregate, the Acadian Gas system includes over 1,000 miles of high-pressure transmission lines and lateral and gathering lines with an aggregate throughput capacity of approximately one Bcf/d and a leased storage facility with approximately three Bcf of storage capacity.

	•	Petrochemical Pipeline Services. Our Petrochemical Pipeline Services segment consists of two petrochemical pipeline systems with an aggregate of 284 miles of pipeline. The Lou-Tex propylene pipeline system consists of a 263-mile pipeline used to transport chemical-grade propylene between Sorento, Louisiana and Mont Belvieu, Texas. The Sabine propylene pipeline system consists of a 21-mile pipeline used to transport polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect in Cameron Parish, Louisiana on a transport-or-pay basis.

	•	NGL Pipeline Services. Our NGL Pipeline Services segment will consist of a 290-mile pipeline system used to transport NGLs from two Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas and related interconnections. We acquired a 223-mile segment of the system in August 2006, and we are in the process of acquiring and constructing other segments of the pipeline. This system is not in operation, but it is currently undergoing modifications, extensions and interconnections that should allow it to transport NGLs beginning in January 2007. Additional expansions to this system are scheduled to be completed during 2007.

Our Relationship with EPCO and Enterprise Products Partners

One of our principal attributes is our relationship with Enterprise Products Partners and EPCO. Our assets connect to various midstream energy assets of Enterprise Products Partners and, therefore, form integral links within Enterprise Products Partners’ value chain. Enterprise Products Partners is a North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, NGLs and crude oil, and is an industry leader in the development of pipeline and other midstream infrastructure in the

continental United States and Gulf of Mexico. Enterprise Products Partners’ value chain is an integrated midstream energy asset network that links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States, Canada and the Gulf of Mexico with domestic consumers and international markets. We believe the operational significance of these assets to Enterprise Products Partners, as well as the alignment of our respective economic interests in them, will result in a collaborative effort to promote their operational efficiency and maximize value.

All of our and Enterprise Products Partners’ management, administrative and operating functions will be performed by employees of EPCO, Enterprise Products Partners’ ultimate parent company under common control by Dan L. Duncan, pursuant to an amended and restated administrative services agreement. Dan L. Duncan and his affiliates will have a significant interest in our partnership through Enterprise Products OLP’s ownership of 34% of the equity interests in our operating subsidiaries and Enterprise Products OLP’s direct ownership of approximately 36.0% of our outstanding common units (or approximately 26.3% if the underwriters’ option to purchase additional units is exercised in full) and indirect ownership of our 2% general partner interest. We believe our relationship with Enterprise Products Partners and EPCO provides us with a distinct advantage in both the operation of our current assets and in the identification and execution of potential future acquisitions that are not otherwise taken by Enterprise Products Partners or Enterprise GP Holdings in accordance with our business opportunity agreements.

Our Business Strategy

Our primary business objectives are to maintain and, over time, to increase our cash available for distributions to our unitholders. Our business strategies to achieve these objectives are to:


	•	optimize the benefits of our economies of scale, strategic location and pipeline connections serving our natural gas, NGL, petrochemical and refining markets;

	•	manage our existing and future asset portfolio to minimize the volatility of our cash flows;

	•	invest in organic growth projects to capitalize on market opportunities which expand our asset base and generate additional cash flow; and

	•	pursue acquisitions of assets and businesses from related parties, or, in accordance with our business opportunity agreements, from third parties.

Our Competitive Strengths

We believe we are well-positioned to achieve our primary objectives and to execute our business strategies successfully because of the following competitive strengths:


	•	our operations currently consist of mature assets and a new NGL pipeline which are expected to generate stable, predictable cash flows;

	•	our assets are strategically located in areas with high demand for our services play a critical role in Enterprise Products Partners’ midstream energy value chain;

	•	Enterprise Products Partners and EPCO have established a reputation in the midstream natural gas and NGL industry as reliable and cost-effective operators;

	•	the senior management team and board of directors of our general partner have extensive industry experience and include some of the most senior officers of Enterprise Products Partners and EPCO;

	•	we have a lower cost of capital than other publicly-traded partnerships that have incentive distribution rights; and

	•	our affiliation with Enterprise Products Partners and its affiliates, may provide us access to attractive acquisition opportunities from them and third parties.

Industry Overview

We are currently engaged in the business of gathering, transporting, marketing, and storing natural gas and transporting, marketing and storing NGLs and petrochemicals. Our business is directly impacted by changes in domestic demand for and production of natural gas, NGLs, propylene and other petrochemical products.

Natural Gas Demand and Production

Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.4 trillion cubic feet, or Tcf, (61.4 Bcf/d) in 2004 to approximately 26.9 Tcf (73.7 Bcf/d) in 2030, representing an average annual growth rate of over 1.12% per year. Most of that increase is expected to occur before 2017, when total U.S. natural gas consumption reaches just over 26.5 Tcf. After 2017, rising natural gas prices are predicted to curb consumption growth and reduce the natural gas share of total energy consumption. The industrial and electricity generation sectors are the largest users of natural gas in the United States. During the last three years, these sectors accounted for approximately 61% of the total natural gas consumed in the United States. In 2004, natural gas represented approximately 24% of all end-user domestic energy requirements. During the last five years, the United States has on average consumed approximately 22.5 Tcf per year, with average annual domestic production of approximately 19.1 Tcf during the same period. Driven by growth in natural gas demand and high natural gas prices, domestic natural gas production is projected to increase from 18.9 Tcf per year to 20.4 Tcf per year between 2004 and 2010.

Midstream Industry

Once natural gas is produced from wells, producers then seek to deliver the natural gas and its components to end-use markets. The midstream natural gas industry is the link between upstream exploration and production activities and downstream end-user markets, and generally consists of natural gas gathering, transportation, processing, storage and fractionation activities. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

The following diagram illustrates the natural gas gathering, processing, fractionation, storage and transportation process. We supply Enterprise Products Partners and our other customers with several gathering, transportation, and storage services for their natural gas, NGL and petrochemical products.

Natural Gas Gathering

Once a well has been completed, the well is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transmission. Offshore gathering uses a similar process, but production platforms provide production handling services, which in the case of a well producing a mixture of oil and gas involves the separation of natural gas from the oil and water

before the natural gas enters the gathering lateral. Gathering laterals then connect to a main or trunk line of larger diameter pipe. The mainline then transports the natural gas collected from the various laterals to an onshore location, typically a treating facility or gas processing plant. Our Natural Gas Pipelines & Services business segment provides for the gathering, transmission, and storage of natural gas in Louisiana, and currently consists of over 1,000 miles of onshore natural gas pipelines.

Natural Gas Treating

Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications. The principal component of natural gas is methane, but most natural gas also contains varying amounts of NGLs including ethane, propane, normal butane, isobutane and natural gasoline. NGLs have economic value and are utilized as a feedstock in the petrochemical and oil refining industries or directly as a heating, engine or industrial fuel. Once separated from the natural gas, NGLs must be handled and transported to its end users through a dedicated pipeline system.

Natural Gas Transportation

Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the processed natural gas to industrial end-users and utilities and to other pipelines. Our Natural Gas Pipelines & Services business segment currently engages in natural gas transportation.

NGL Fractionation

NGL fractionation facilities separate mixed NGL streams into discrete NGL products, including ethane, propane, normal butane, isobutane, natural gasoline and propylene, which are also called “purity NGLs.” The three primary sources of mixed NGLs fractionated in the United States are (i) domestic natural gas processing plants, (ii) domestic crude oil refineries and (iii) imports of butane and propane mixtures. NGLs are fractionated by heating mixed NGL streams and passing them through a series of distillation towers, in order to take advantage of the differing boiling points of the various NGL products. As the temperature of the NGL stream is increased, the lightest (lowest boiling point) NGL product boils off to the top of the tower where it is condensed and routed to storage. The mixture from the bottom of the first tower is then moved into the next tower where the process is repeated, and a heavier NGL product is separated and stored. This process is repeated until the NGLs have been separated into all of their components. Since the fractionation process requires large quantities of heat, energy costs are a major component of the total cost of fractionation.

NGL Transportation

NGLs are transported to market by means of pipelines, pressurized barges, rail car and tank trucks. The method of transportation utilized depends on, among other things, the existing resources of the transporter, the locations of the production points and the delivery points, cost-efficiency and the quantity of NGLs being transported. Pipelines are generally the most cost-efficient mode of transportation when large, steady volumes of NGLs are to be delivered. Our Petrochemical Pipeline Services segment consists of two petrochemical pipeline systems with an aggregate of 284 miles of pipeline that provide for the transportation of propylene in Texas and Louisiana.

In general, refinery-grade propylene (a mixture of propane and propylene) is separated into either polymer-grade propylene or chemical-grade propylene along with by-products of propane and mixed butane. Polymer-grade propylene can also be produced from chemical-grade propylene feedstock. Chemical-grade propylene is also a by-product of olefin (ethylene) production. The demand for polymer-grade propylene is attributable to the manufacture of polypropylene, which has a variety of end uses, including packaging film, fiber for carpets and upholstery and molded plastic parts for appliance, automotive, houseware and medical products. Chemical-grade propylene is a basic petrochemical used in plastics, synthetic fibers and foams.

NGL Storage

After NGLs are fractionated, the fractionated products are stored for customers when they are unable or do not wish to take immediate delivery. NGL storage customers may include both NGL producers, who sell to end users, and NGL end users, such as retail propane companies and petrochemical facilities. Both the producers and the end users seek to store NGL products to ensure an adequate supply for their respective customers over the course of the year, particularly during periods of increased demand. We maintain NGL storage facilities as part of our NGL & Petrochemical Storage Services business segment that help us meet this industry need.

NGL & Petrochemical Storage Services Segment

General

Our NGL & Petrochemical Storage Services segment consists of three integrated and strategically located underground storage facilities in Mont Belvieu, Texas, which we refer to as Mont Belvieu East, West and North storage facilities. We have multiple pipelines that interconnect these facilities, and each facility is comprised of a network of caverns located several hundred feet below ground. These facilities include 33 storage caverns with an aggregate underground storage capacity of approximately 100 MMBbls, and a brine system with approximately 20 MMBbls of above-ground storage pit capacity and two brine production wells.

These assets, known as Mont Belvieu Caverns, accept, store and deliver NGLs and petrochemical products, such as ethane and propane, for industrial customers located along the upper Texas Gulf Coast. This area has the largest concentration of petrochemical plants and refineries in the United States. The storage facilities are interconnected by multiple pipelines to other producing and offtake facilities throughout the Gulf Coast, including the largest NGL import/export facility in this region owned by Enterprise Products Partners, as well as connections to the Rocky Mountain and Midwest regions via the Seminole pipeline and to the Louisiana Gulf Coast via the Lou-Tex NGL pipeline, which are NGL pipelines owned by Enterprise Products Partners.


	•	Mont Belvieu East Facility. The Mont Belvieu East facility is the largest of the three facilities. This facility consists of 13 storage caverns available for service with an underground storage capacity of approximately 55 MMBbls and above-ground brine pit capacity of approximately 10 MMBbls. This facility also has two brine production wells.

	•	Mont Belvieu West Facility. The Mont Belvieu West facility consists of ten caverns available for service with an underground storage capacity of approximately 15 MMBbls and above-ground brine pit capacity of approximately 2 MMBbls.

	•	Mont Belvieu North Facility. The Mont Belvieu North facility consists of ten caverns available for service with an underground storage capacity of approximately 30 MMBbls and above-ground brine pit capacity of approximately 8 MMBbls.

Mont Belvieu Caverns derives essentially all of its revenues from four main sources. These sources are:


	•	storage reservation fees;

	•	excess storage fees;

	•	throughput fees; and

	•	brine production and storage.

We charge our customers monthly storage reservation fees to reserve a specific storage capacity in our underground caverns. The customers pay reservation fees based on the quantity of capacity reserved rather than on the amount of reserved capacity actually utilized. When a customer exceeds its reserved capacity, we charge those customers an excess storage fee. In addition, we charge our customers throughput fees based on volumes injected and withdrawn from the storage facility. Lastly, brine production revenues are derived from customers that use brine in the production of feedstocks for production of chlorine and caustic soda, which is

used in the production of PVC and for industrial products used in crude oil production and fractionation. Brine is produced by injecting fresh water into the well to create cavern space within the salt dome. This process enables brine to be produced for our customer as well as for developing new wells for product storage.

The picture below depicts a typical storage cavern. Mont Belvieu Caverns receives NGL and petrochemical products from related and third party pipelines and facilities. As this product is injected into the well it displaces brine that is then transferred to the above-ground storage pit. When it is time to redeliver the product, brine is then injected back into the well displacing the product being stored. This product is delivered to third party pipelines or other facilities.

Customers

Our customers include a broad range of NGL and petrochemical producers and consumers, including many of the petrochemical facilities and refineries in the Texas Gulf Coast and the Louisiana Gulf Coast. Our five largest third-party customers, which accounted for 39% of our total storage revenues for the six months ended June 30, 2006, were ExxonMobil, Chevron/Phillips, Dow, Shell and Westlake Petrochemicals. Our underground storage services to Enterprise Products Partners for the storage of NGLs and petrochemicals accounted for 35% of our total storage revenues for the six months ended June 30, 2006.

Contracts

We have a broad range of customers with contract terms that vary from month-to-month to long-term contracts with durations of one to ten years. We currently offer our customers, in various quantities and at varying terms, two main types of storage contracts: multi-product fungible storage and segregated product storage. Multi-product fungible storage allows customers to store any combination of fungible products. Segregated product storage allows customers to store non-fungible products such as propylene, ethylene and

naphtha. Segregated storage allows a customer to lease an entire storage cavern and have its own product injected and withdrawn without having its product commingled. We evaluate pricing, volume and availability for storage on a case-by-case basis.

Related Party Contracts

Currently, Enterprise Products OLP has seven contracts for storage with Mont Belvieu Caverns that include multi-product fungible storage for its NGL marketing activities, and for feedstocks for its isomerization, iso-octane, NGL fractionation, and propylene fractionation businesses and segregated product storage for polymer grade propylene that is produced at propylene fractionation facilities. These contracts have a duration of five to ten years. Please read “Certain Relationships and Related Party Transactions.”

For the years ended December 31, 2005, 2004 and 2003, we recorded $17.6 million, $17.0 million and $17.3 million, respectively, in storage revenues from Enterprise Products Partners. For the six months ended June 30, 2006, we recorded $8.7 million in storage revenues from Enterprise Products Partners.

Seasonality

We operate our NGL and related product storage facilities based on the needs and requirements of our customers. We usually experience an increase in the demand for storage services during the spring and summer months due to increased feedstock storage requirements for motor gasoline production and a decrease during the fall and winter months when propane inventories are being drawn for heating needs. In general, our import volumes peak during the spring and summer months and our export volumes are at their highest levels during the winter months. Typically, we do not experience any significant seasonality with our petrochemical customers because those customers withdraw and inject petrochemicals on a regular basis.

Competition

Our competitors in the NGL, petrochemical and related product storage business are integrated major oil companies, chemical companies and other storage and pipeline companies. We compete with other storage service providers primarily in terms of the fees charged, number of pipeline connections and operational dependability. We are distinguished from our competitors by our extensive pipeline connections to petrochemical plants and imports from the Houston ship channel. Our most direct competitors include Mont Belvieu Storage Partners, L.P., Targa Resources, Texas Brine and ONEOK.

An increase in competition in the market could arise from new ventures or expanded operations from existing competitors. Other competitive factors include (1) the quantity, location and physical flow characteristic of interconnected pipelines, (2) the costs of services and rates of our competitors and (3) NGL product commodity prices in the Gulf Coast region as compared to prices in other regions.

NGL and Petrochemical Sources and Transportation Options

We generally receive the NGLs and petrochemicals that we inject into our facilities, and our customers generally choose to transport the NGLs that we withdraw from our facilities, through the intrastate and interstate NGL and petrochemical pipelines that interconnect with our storage facilities, including Black Lake, Lakemont, Lou-Tex NGL Pipeline, Skelly-Belvieu, Cypress, Seadrift, Chaparral, West Texas and Panola. We are also connected to some of Enterprise Products Partners’ pipelines, including the Seminole pipeline, the Port Neches Pipeline and the Channel Pipeline system. In addition we are also connected to the truck and rail loading and unloading facilities owned by Enterprise Products Partners. We are also connected to numerous other pipelines through several interconnecting pipelines to ARCO Junction, which is a large pipeline hub in Mont Belvieu, Texas. We are also connected to multiple third-party pipelines owned by Equistar, ExxonMobil, ONEOK, Huntsman, ChevronPhillips, Dow, Valero and Shell. In addition, we are connected to all of the NGL fractionators in Mont Belvieu that are owned by Enterprise Products Partners, Targa, ONEOK and Gulf Coast Fractionators. We also receive specialized NGL products from the ExxonMobil Fractionator at Beaumont, Texas and the ConocoPhillips Fractionator at Sweeny, Texas.

Mont Belvieu Expansion Opportunities

We are evaluating several projects to better integrate the three Mont Belvieu facilities. These projects include additional pipelines to more efficiently connect the facilities and additional entries into certain wells to increase flow rates. We are also evaluating projects that would allow us to store natural gas. The contemplated Mont Belvieu expansion project (the “Mont Belvieu Expansion”) is currently anticipated to include new entries into existing wells, the conversion of existing wells to store natural gas and the installation of new piping and certain related facilities, which may be commenced during 2007 in the range of $25 to $75 million. Additional expenditures of up to $200 million may be made during 2008 and 2009. Pursuant to the Mont Belvieu limited liability company agreement, Enterprise Products OLP may, in its sole discretion, fund a portion of any costs related to these projects. Additionally, we may finance any such projects through borrowings under our credit facility or the issuance of debt or additional equity. For a further description of our agreements with Enterprise Products Partners relating to these potential expansion opportunities, please read “Certain Relationships and Related Party Transactions — Mont Belvieu Caverns Limited Liability Company Agreement — Mont Belvieu Caverns Expansion Capital Agreements.”

Import/Export Business

Enterprise Products Partners has a growing import/export business in which it imports various NGL products and transports these to and from our facilities in Mont Belvieu, Texas. These products can be stored in our underground storage facilities for our customers. Enterprise Products Partners is in the process of expanding this import/export capability and expects to be completed in the fourth quarter of 2006.

Natural Gas Pipelines & Services Segment

General

Our Natural Gas Pipelines & Services segment consists of the Acadian Gas system, which is an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, located primarily in the natural gas market area of the Baton Rouge — New Orleans — Mississippi River corridor. In the aggregate, the Acadian Gas system includes over 1,000 miles of high-pressure transmission lines and connected lateral segments with an aggregate throughput capacity of approximately one Bcf/d and three Bcf of storage capacity.

The Acadian Gas system has over 150 physical end-user market direct connections. In addition, the system interconnects with 12 interstate and 4 intrastate pipelines through 50 separate interconnections, has a bi-directional interconnect with the largest U.S. natural gas marketplace at the Henry Hub, and is directly connected to six merchant and utility electric generation facilities with over 6,000 megawatts of generating capacity. The numerous interconnections allow the Acadian Gas system to leverage basis differentials across the South Louisiana pipeline network, maintain a diversified supply portfolio and create capacity and transportation opportunities for its shippers. The Acadian Gas system’s bi-directional interconnect with the Henry Hub provides physical and financial pricing flexibility, in addition to facilitating access to the many buyers and sellers of natural gas at the hub.

The Acadian Gas system includes the following assets:


	•	Acadian Pipeline. The Acadian pipeline is located in southern Louisiana and consists of approximately 438 miles of high-pressure transmission lines and smaller diameter lateral and gathering lines ranging from 12 inches to 24 inches in diameter. The Acadian pipeline receives natural gas at numerous interconnections with natural gas production facilities and from third-party pipelines and delivers the natural gas to customers’ facilities in southern Louisiana. Through numerous interconnections with other pipelines, including receipt and delivery capability at the Henry Hub, the Acadian pipeline has the capability to deliver gas to markets that it does not physically reach. The Acadian pipeline has a throughput capacity of approximately 650 MMcf/d. The Acadian pipeline maintains multiple active


		interconnects with the Cypress pipeline to facilitate gas deliveries between the systems as may be required to meet customer needs.


	•	Cypress Pipeline. The Cypress pipeline is located in south central Louisiana and consists of approximately 577 miles of transmission lines and smaller diameter lateral and gathering lines ranging from 10 inches to 22 inches in diameter. This pipeline has interconnections with many of the interstate and intrastate pipeline systems operating in southern Louisiana and has a throughput capacity of approximately 350 MMcf/d. The Cypress pipeline was originally built to gather onshore Louisiana natural gas supplies and to provide natural gas pipeline service to the greater Baton Rouge industrial market, in particular, the ExxonMobil Baton Rouge Refinery. Through the 1950’s and 1960’s, it was expanded to access the interstate pipeline supply network and the Geismar, Louisiana and Donaldsonville, Louisiana industrial market areas. The Cypress pipeline also has the capability to access deepwater gas production through an interconnect with the Nautilus Gas Pipeline system and numerous third-party pipelines.

	•	Evangeline Pipeline. The Evangeline pipeline is a 27-mile pipeline extending from Taft, Louisiana to Westwego, Louisiana. The Evangeline pipeline, which consists mainly of transmission lines ranging from 20 inches to 26 inches in diameter, connects with three Entergy Louisiana natural gas fired electric generation stations, the Acadian pipeline and a pipeline owned by the Columbia Gulf Transmission Company. We indirectly own approximately 49.5% of the ownership interests in the Evangeline pipeline. A subsidiary of ConocoPhillips and a private investor own the remaining interests in Evangeline.

	•	Underground Storage Facility. The storage assets in the Acadian Gas system consist of a leased underground natural gas storage facility located at the center of the Acadian Pipeline system near Napoleonville, Louisiana. The storage facility has approximately 3.0 Bcf of storage capacity, 220 MMcf/d of withdrawal capacity and a maximum of 80 MMcf/d of injection capacity. This facility is designed to handle high levels of injections and withdrawals of natural gas to meet load swings and to cover major supply interruption events, such as hurricanes and temporary losses of production. In addition, the storage facility permits sustained periods of high natural gas deliveries and has the ability to switch quickly from full injection to full withdrawal. An affiliate of Shell is leasing the storage facility to Acadian Gas through December 31, 2012. The term of this contract does not provide for an additional renewal period. However, Shell has agreed to enter into diligent negotiations with us under similar terms and conditions for an extension if we wish to extend the lease agreement beyond December 2012. Acadian Gas is the operator of this underground storage facility and owns 75% of its leased storage, withdrawal and injection capacity. A third party owns the remaining 25% interest.

System Throughput

Natural gas throughput on the Acadian Gas system consists of a combination of natural gas sales volumes owned by us and transportation volumes delivered on behalf of third-party shippers, with marketing volumes and transportation volumes representing approximately 40% and 60%, respectively, of the average daily gas volumes for the first six months of 2006. The following table summarizes Acadian Gas system’s sales and transportation volumes for the periods indicated:

Average Gas Sales and Transportation Volumes (Bbtu/d)


	Years Ended						Six Months
	December 31,						Ended
	2003		2004		2005		June 30, 2006

Gas Sales Volumes		331		330		317		343
Transportation Volume		269		315		323		446

Total System Volume		600		645		640		789

100

Customers

The Acadian Gas system transported approximately 789 Bbtu/d of natural gas to its customers during the first six months of 2006. We have long-standing relationships with a majority of our customers. Many of our customers purchase and transport a substantial portion of their natural gas requirements through the Acadian Gas system and for some customers our pipelines are the only access point for their natural gas supplies. Our customers include:


	•	electric generating facilities, such as those owned by Entergy Louisiana and Calpine Corporation;

	•	integrated refining and petrochemical facilities, such as ExxonMobil’s Baton Rouge Complex;

	•	local distribution companies and various city and parish systems; and

	•	other industrial and commercial customers of varying size.

The Acadian Gas system has a diversified customer base, with its largest customer representing only 9% of its total revenue in 2005 and the top ten customers representing only 40% of its total revenue in 2005.

Contracts and Transportation Services

In addition to its marketing gas activities, the Acadian Gas system provides fee-based gas transportation services for producers and gas marketing companies under intrastate and interruptible NGPA Section 311 transportation contracts. The primary term of these transportation service contracts may vary from month-to-month to longer-term contracts, with durations typically of one to three years. The revenues derived from these gas transportation contracts are based on the quantities of gas delivered multiplied by the per-unit transportation rate paid. Based on volumes moved, the most significant shippers on the Acadian Gas system include ExxonMobil, Coral Energy Resources, BP Energy and BG Energy Merchants. These shippers transport gas on the Acadian Gas system to meet the natural gas requirements of their affiliated industrial and power generation facilities, and to market commodity gas services to third parties. ExxonMobil is the most significant long-term shipper on the Acadian Gas system, and we entered into a long-term gas transportation agreement with ExxonMobil in 1993 in conjunction with our acquisition of the Cypress pipeline, which was formerly owned and operated by ExxonMobil. The primary term of this Agreement expires on December 1, 2006, but the parties entered into an amendment to extend the term until November 2009. During the six months ended June 30, 2006, ExxonMobil shipped approximately 125 Bbtu/d on the Acadian Gas system utilizing our system as the primary fuel gas pipeline service provider for its Baton Rouge Refinery and Chemical complex.

Natural Gas Sales

The Acadian Gas system is currently connected to approximately 116 customers with an approximate total gas requirement of over 3.0 Bcf/d. The Acadian Gas system has maintained active and long-term relationships, and currently has long-term natural gas sales or transportation contracts, with most of these customers. Our natural gas sales arrangements are implemented under contracts with market-based pricing indices that correspond to the pricing indices utilized in our gas purchasing activities.

The majority of gas sales on the Acadian Gas system are made pursuant to long-term contracts, most of which are at least one year in duration. Gas sales are also made under short-term agreements, which generally range from one day to one month. Much of our gas sales volume is under agreements that provide for minimum annual volumes to be delivered at Henry Hub indexed market prices (determined monthly), plus a predetermined adjustment or differential. The Acadian Gas system has historically received higher margins under long-term contracts that provide customers with supply certainty as well as value added services to ensure gas supplies through dedicated facilities. These additional services are necessary to accommodate large swings in a customers’ natural gas requirement, which may vary hourly, daily and monthly.

The Acadian Gas system’s most significant natural gas sales contract is a 21-year arrangement with Evangeline, which was entered into in 1991, and includes minimum annual quantities. Evangeline uses these natural gas volumes to meet its own supply obligation under a corresponding sales agreement with Entergy

101

Louisiana, its only customer. Under the Entergy Louisiana gas sales contract, Evangeline is obligated to make available for sale and deliver to Entergy Louisiana certain specified minimum quantities of gas on a hourly, daily, monthly and annual basis. The gas sales contract provides for minimum annual quantities of 36.75 Bbtus until the contract expires on January 1, 2013 (which is coterminous with the natural gas purchase commitment with ConocoPhillips described below). Please read “— Evangeline Long-Term Debt” below for a discussion regarding the use of proceeds by Evangeline from these natural gas sales.

In connection with Acadian Gas’ gas sales contract with Evangeline, a portion of the revenues received are attributable to a “seller’s margin” agreement contained with the contract. The “seller’s margin” set forth in the contract is a fixed dollar amount paid per MMBtu per month in the first contract year and adjusted upwards in successive years. Seller’s margin is used to calculate fees incurred on the contract when a buyer exercises an option to reduce the minimum annual quantity or when firm gas is delivered pursuant to the contract.

The electric utility and industrial customers of Acadian Gas system normally consume the natural gas in their own operations for fuel or feedstock, while local distribution companies and city-gate systems generally resell the natural gas to the customers of their respective gas pipeline systems.

Natural Gas Purchases

The Acadian Gas system currently purchases gas supply from 41 different gas producers through 59 separate gas production receipt locations. Substantially all of the Acadian Gas system’s natural gas requirements are purchased under contracts that contain market-responsive pricing provisions. The Acadian Gas system’s most significant long-term gas purchase commitment is with ConocoPhillips, which was entered into in 1991 as part of the formation of Evangeline Gas Pipeline Company, L.P. This gas purchase contract expires on January 1, 2013 (which is coterminous with the natural gas sales agreement with Evangeline described above) and provides for minimum annual quantities of natural gas to be purchased by the Acadian Gas system, similar in structure to the minimum annual obligations between Acadian Gas system and Evangeline, and the corresponding obligations between Evangeline and Entergy Louisiana. The pricing terms of the gas purchase contract and the Entergy Louisiana gas sales contract are based on a weighted-average cost of natural gas each month (subject to certain market index price ceilings and incentive margins), plus a pre-determined margin. The amount of natural gas purchased pursuant to this contract totaled 17.4 Bbtus in 2005, 18.2 Bbtus in 2004 and 18.2 Bbtus in 2003. The amounts paid by the Acadian Gas System for natural gas purchased under this contract totaled $148.3 million in 2005, $112.7 million in 2004 and $100.3 million in 2003.

Natural Gas Interconnections

General. The Acadian Gas system procures gas supply from natural gas production facilities, third party natural gas pipelines, and market center pipeline hubs such as the Henry Hub and the Nautilus Hub operated by third parties. The Acadian Gas system has approximately 50 separate pipeline-to-pipeline interconnects with 12 interstate pipeline systems, and four unaffiliated intrastate pipeline systems. These third-party gas supplies in support of Acadian Gas system’s gas marketing activities and as receipt volumes for gas transportation activities may be sourced from any of these locations as pipeline pressures, facility interconnect capacities and landed gas pricing levels will dictate.

The Henry Hub. The Acadian Gas system includes a bi-directional interconnect with the Henry Hub which is generally considered to be one of the most liquid natural gas market locations in North America. The Henry Hub has interconnects with nine interstate and four intrastate pipelines providing shippers with access to pipelines reaching markets in the Midwest, Northeast, Southeast, and Gulf Coast regions of the United States. The Henry Hub is also the delivery point for the New York Mercantile Exchange (NYMEX) natural gas futures contract with NYMEX deliveries occurring at the Henry Hub being handled the same as cash-market transactions, thereby providing the connected Henry Hub participants with additional market flexibility.

The Nautilus Hub. The Acadian Gas system is also connected to the Nautilus Hub, which is the terminal end of the Nautilus Gas Pipeline system. The Nautilus Gas Pipeline system is a 101-mile, 30-inch

102

FERC- regulated gas transmission system that gathers deepwater Gulf of Mexico natural gas production for delivery onshore in St. Mary Parish, Louisiana at the Neptune natural gas processing plant, which is operated by Enterprise Products Partners. After natural gas is processed at the Neptune facility, it is redelivered into the Nautilus Hub which has seven separate interconnects with interstate and intrastate gas pipeline systems, including the Acadian Gas system.

Evangeline Long-Term Debt

In connection with the acquisition of the Entergy Louisiana natural gas sales contract and construction of the Evangeline pipeline, Evangeline entered into a long-term debt arrangement consisting of 9.9% fixed interest rate senior secured notes due December 2010, or the Series B Notes, and a $7.5 million subordinated note payable to Evangeline Northwest Corporation, or the ENC Note. The Series B notes are collateralized by: (i) Evangeline’s property, plant and equipment; (ii) proceeds from the Entergy Louisiana natural gas sales contract; and (iii) a debt service reserve requirement. Scheduled principal repayments on the Series B notes are $5 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. Evangeline incurred the ENC Note obligations in connection with its acquisition of the Entergy Louisiana natural gas sales contract in 1991. The ENC Note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B note holders are either fully cash secured through debt service accounts or have been completely repaid. Substantially all of the net proceeds received by Evangeline from its contracts with Entergy Louisiana are used to pay off the Series B notes and ENC Note.

Entergy Louisiana’s Option

Entergy Louisiana has the option to purchase the Evangeline pipeline system for a nominal price, plus the complete performance and compliance with the gas sales contract. The option period begins on the earlier of July 1, 2010 or upon the payment in full of the Series B Notes and the ENC Note, and terminates on December 31, 2012. We cannot know when, or if, Entergy Louisiana will exercise this option. Factors that may influence Entergy Louisiana’s decision include, but are not limited to, Entergy Louisiana’s future business plans, natural gas procurement strategies, required regulatory approvals, and the pipeline system’s residual value, if any, at the time the option is exercisable.

Commodity Price Risk

With regard to physical marketing gas activities, the Acadian Gas system purchases gas in quantities and under pricing terms that mirror its sales obligations. Within the transportation services function, the Acadian Gas system transports quantities of gas on behalf of others, with those shippers being responsible for managing any commodity price risk that may be associated with matching gas purchases with gas sale. The Acadian Gas system does not engage in any type of commodity hedging, nor any futures, options, or basis trading for the purpose of attempting to create or optimize a proprietary trading position. Accordingly, the Acadian Gas system does not manage or utilize a strategy that would involve trading of financial positions. Certain physical customers of the Acadian Gas system will from time to time request the ability to control the volatility inherent in a monthly indexed natural gas sales arrangement, which requires that the Acadian Gas system take a position in the futures market corresponding to the hedge request of that customer. When this transaction takes place, it is only at the request of the customer, and only in a volume and for a time period that corresponds to coverage of that customer’s request, and as it would relate to that customer’s physical delivery contract with the Acadian Gas system.

Seasonality

Typically, the Acadian Gas system experiences higher throughput rates during the summer months as gas-fired power generation facilities increase output to satisfy residential and commercial demand for electricity for air conditioning. Likewise, seasonality impacts the timing of injections and withdrawals at our natural gas storage facility. In the winter months, natural gas is needed as fuel for residential and commercial heating, generally increasing the need for deliveries to local distribution companies and city-gate stations.

103

Competition

The Acadian Gas system competes with other onshore natural gas pipelines on the basis of price (in terms of transportation fees or natural gas selling prices), service, reliability and flexibility. The competitive position of the Acadian Gas system within the onshore South Louisiana market is enhanced by its longstanding relationships with its connected customers and the somewhat limited number of alternative delivery pipelines capable of being connected to those customers.

Petrochemical Pipeline Services Segment

General

Our Petrochemical Pipeline Services segment consists of two petrochemical pipeline systems with an aggregate of 284 miles of pipeline that provide for the transportation of propylene in Texas and Louisiana. This segment includes the following assets:


	•	Lou-Tex Propylene Pipeline. The Lou-Tex pipeline consists of a 263-mile, 10-inch pipeline used to transport chemical-grade propylene between Sorrento, Louisiana and Mont Belvieu, Texas. Currently, this pipeline is used to transport chemical-grade propylene from production facilities in Louisiana to customers in Louisiana and Texas under transportation contracts that Enterprise Products OLP has with Shell and ExxonMobil. The chemical-grade propylene transported for Shell originates from the Shell Sorrento underground storage facility and is delivered to various delivery points between an underground storage facility in Sorrento, Louisiana and an underground storage facility in Mont Belvieu, Texas owned by Mont Belvieu Caverns. The delivery points on the Lou-Tex pipeline include Vulcan, Westlake Lake Charles, Beaumont Novus, and Shell’s Texas chemical grade propylene delivery system. The chemical-grade propylene delivered for Exxon originates from the Exxon Baton Rouge refining and chemical complex and is delivered to an underground storage well in Mont Belvieu, Texas owned by Mont Belvieu Caverns. The Lou-Tex pipeline was constructed in 1997 and acquired by Enterprise Products Partners in March 2000 from an affiliate of Shell.

	•	Sabine Propylene Pipeline. The Sabine pipeline consists of a 21-mile, 8-inch pipeline used to transport polymer-grade propylene that begins in Groves, Texas and terminates at a connection to Enterprise Products Partners’ Lake Charles propylene line in Cameron Parish, Louisiana. The polymer-grade propylene transported for Shell originates from the TOTAL/BASF Port Arthur cracker facility and is delivered to the Basell polypropylene facility in Lake Charles, Louisiana. The pipeline was constructed by Enterprise Products Partners and placed in service in 2002.

Customers and Contracts

Customers. Shell and ExxonMobil are the only customers that use the Lou-Tex pipeline. Shell is the only customer that uses the Sabine pipeline.

Contracts. Enterprise Products Partners has entered into separate product exchange agreements with Shell and ExxonMobil involving the use of our Sabine and Lou-Tex pipelines. Concurrently with the closing of this offering, Enterprise Products Partners will assign these exchange agreements to us. Through these exchange agreements, we will agree to receive propylene product in one location and deliver it to another location.


	•	Shell Exchange Agreements. We will become a party to separate product exchange agreements with Shell for the use of the Lou-Tex and Sabine pipelines. The term of the Lou-Tex pipeline agreement expires on March 1, 2020, but will continue on an annual basis subject to termination by either party. The exchange fees paid by Shell are fixed until such time as a published power index in Louisiana becomes available and the parties agree to use such index. The term of the Sabine pipeline agreement expires on November 1, 2011, but will continue on an annual basis subject to termination by either party. The exchange fees paid by Shell are adjusted yearly based on the U.S. Department of Labor wage index and the yearly operating costs of the Sabine pipeline. Shell is obligated to meet minimum

104


		delivery requirements under the Lou-Tex and Sabine agreements. If Shell fails to meet such minimum delivery requirements, it will be obligated to pay a deficiency fee to us.


	•	Exxon Exchange Agreement. We will become a party to a product exchange agreement with ExxonMobil for the use of the Lou-Tex pipeline. The term of the Lou-Tex exchange agreement expires on June 1, 2008, but will continue on a monthly basis subject to termination by either party. The exchange fees paid by ExxonMobil are based on the volume of chemical grade propylene delivered to Enterprise Products Partners and us.

Related Party Contracts

Enterprise Products Partners will assign the exchange agreements for the use of the Lou-Tex and Sabine pipelines with Shell and ExxonMobil to us concurrently with the closing of this offering. Prior to 2004, the Sabine pipeline was regulated by the FERC. The Lou-Tex pipeline was also subject to the FERC’s jurisdiction until 2005. For the periods in which the Sabine pipeline and the Lou-Tex pipeline were subject to FERC regulations, related party revenues with Enterprise Products Partners were based on the maximum tariff rate allowed for each system. We continued to charge Enterprise Products Partners such maximum transportation rates after both entities were declared exempt from FERC oversight. The assignment of these contracts to us concurrently with the closing of this offering will make the tariff charged by us to equal the rates charged to ExxonMobil and Shell.

Throughput

The following table summarizes throughput of each of our petrochemical pipelines for the periods indicated:

Throughput (Bbls/d)(1)

Years Ended

Six Months

December 31,

Ended

Capacity

2003

2004

2005

June 30, 2006

(Bbls/d)

Total

Lou-Tex Propylene Pipeline

52,500

28,883

27,810

23,066

25,590

Sabine Propylene Pipeline

20,600

11,265

11,336

10,394

9,691


(1)		The maximum number of barrels that these systems can transport per day depends on the operating balance achieved at a given time between various segments of the systems. Because the balance is dependent upon the mix of receipt and delivery capabilities, the exact capacities of the systems cannot be stated. We measure the utilization rates of our NGL and petrochemical pipelines in terms of throughput (on a net basis in accordance with our ownership interest).

Seasonality

Our propylene transportation business has historically exhibited little seasonality.

Competition

Our petrochemical pipelines encounter competition from fully integrated oil companies and various petrochemical companies. Our petrochemical transportation competitors have varying levels of financial and personnel resources and competition generally revolves around price, service, logistics and location.

NGL Pipeline Services Segment

General

Our NGL Pipeline Services segment will consist of a 290-mile intrastate pipeline system and related interconnections to be used to transport NGLs from two fractionation facilities located in South Texas to Mont

105

Belvieu, Texas. The South Texas NGL pipeline system is not in operation, but it is currently undergoing modifications, extensions and interconnections to allow it to transport NGLs beginning in January 2007, which we refer to as Phase I. Enterprise Products Partners purchased the 223-mile segment of pipeline, ranging from 12 inches to 16 inches in diameter, from ExxonMobil Pipeline Company in August 2006. This segment of the South Texas NGL pipeline system originates in Corpus Christi, Texas and extends to Pasadena, Texas. During Phase I, we will:

(1) construct 45 miles of pipeline laterals to connect the two fractionation facilities to the 223-mile segment of our South Texas NGL pipeline system;

(2) lease from TEPPCO Partners a 10-mile, 10-inch interconnecting pipeline extending from Pasadena, Texas to Baytown, Texas; and

(3) acquire an additional 10-mile, 18-inch segment of pipeline from TEPPCO Partners, which will connect the leased TEPPCO pipeline to Mont Belvieu, Texas. The purchase of the 10-mile segment of 18-inch pipeline from TEPPCO Partners is for an aggregate purchase price of $8 million. The primary term of the pipeline lease will expire on July 31, 2007, and will continue on a month-to-month basis subject to termination by either party upon thirty days notice.

During Phase II, we will construct 21 miles of 18-inch pipeline to replace the leased 10-mile, 10-inch pipeline and the 12-inch segments of the pipeline acquired from ExxonMobil. The Phase II upgrade will provide a significant increase in pipeline capacity and is expected to be operational during the third quarter of 2007.

Customer and Related Party Contract

The sole customer of our NGL Pipeline Services segment will be Enterprise Products Partners, which will use the South Texas NGL pipeline system to ship NGLs processed at the Shoup fractionation plant in Corpus Christi, Texas, the Armstrong fractionation plant located near Victoria, Texas and NGLs purchased from third parties in South Texas to Mont Belvieu, Texas. Upon the closing of this offering, we will enter into a ten-year transportation contract with Enterprise Products Partners that will include all of the volumes of NGLs transported on the South Texas NGL pipeline system. Under this contract, Enterprise Products Partners will pay us a dedication fee of $0.02 per gallon for all NGLs produced at the Shoup and Armstrong fractionation plants whether or not Enterprise Products Partners ships any NGLs on the South Texas NGL pipeline system. We will not take title to the products transported on the South Texas NGL pipeline system; rather, Enterprise Products Partners will retain title and the associated commodity risk.

Revenues

Revenues from the dedication fee of $0.02 per gallon of NGLs produced at Enterprise Products Partners’ Shoup and Armstrong fractionation plants will represent substantially all of the revenues for our NGL Pipeline Services Segment and South Texas NGL pipeline system. These NGL volumes have varied during recent periods and may vary in the future. Because the South Texas NGL pipeline system provides transportation services to Enterprise Products Partners on a dedicated fee basis, the results of our operations are dependent upon the level of production of NGLs from the Shoup and Armstrong fractionation plants. If one of the plants shuts down or otherwise reduces production, our revenues would decrease.

Seasonality

Our NGL Pipeline Services segment does not exhibit a significant degree of seasonality.

Supplies

NGL Supply

The sources of the NGLs to be transported on our NGL pipeline system originates primarily from the Shoup fractionation plant located in Corpus, Christi, Texas and the Armstrong fractionation plant located 26 miles north of Victoria, Texas.

106


	•	Shoup Fractionation Plant. The Shoup fractionation plant, located in Corpus Christi, Texas, separates a mixed NGL stream into its components such as purity ethane, propane, mixed butane and natural gasoline. The fractionator has a capacity of 69,000 Bbls/d and produces purity ethane, propane and butane/gasoline streams. The facility fractionates mixed NGLs from 6 gas processing plants located throughout South Texas and delivered to the fractionation plant by approximately 350 miles of NGL gathering pipelines.

	•	Armstrong Fractionation Plant. The Armstrong fractionation plant is located adjacent to the Armstrong gas processing plant in Dewitt County, Texas. The fractionator has a capacity of 18,000 Bbls/d and fractionates mixed NGLs sourced from the Armstrong processing plant exclusively. The facility produces purity ethane, propane, mixed butane and natural gasoline. The Armstrong gas processing plant is a double train expander facility with approximately 250 MMcf/d of processing capacity.

The Shoup and Armstrong fractionation plants produced the following aggregate amounts of NGLs during the periods set forth below:


		NGLs Produced
Period		(Bbls/d)

2003		56,752
2004		66,557
2005		64,505
2006 (six months ended June 30)		65,250

Natural Gas Supply

The natural gas that supplies the gas processing plants which provide the NGLs for the South Texas NGL pipeline system is sourced from the prolific Texas Gulf Coast producing area. Production trends based on 2005 EIA data show a 1% per year increase over the last 25 years. New drilling permits (per IHS Inc.) and rig counts (per Baker Hughes) have also increased 5% per year over the last three years. The EIA report on production of rich gas also shows an annual average increase of 1% over the last 25 years. New resources of rich gas may exist in the Cretaceous sands of southwest Texas and the Oligocene Vicksburg below 14,000’ of South Texas. In the middle Gulf Coast, rich Wilcox gas is found in the 10,000-15,000’ depth range. Shale gas may also have a large potential in these areas with expected high liquids content.

Employees

We do not have any employees. EPCO employs most of the persons necessary for the operation of our business. At September 30, 2006, EPCO had approximately 80 dedicated employees and 176 employees that share a portion of their time in the management and operations of our business, none of whom were members of a union. We will continue to reimburse EPCO for the costs of all employees providing services to us. For a detailed discussion of our related party transactions with EPCO, please read “Certain Relationships and Related Party Transactions.” In addition to EPCO employees, we will engage various contract maintenance and other personnel who will support our operations.

Environmental Matters

General

We are subject to extensive federal, state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including environmental quality and pollution control, community right-to-know, safety and other matters. These laws and regulations may, in certain instances, require us to restrict the way we handle or dispose of our wastes, limit or prohibit construction activities in environmentally sensitive areas, remedy the environmental effects of the disposal or release of certain substances at current and former operating sites or halt the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

107

We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as claims for damages to property, employees, other persons and the environment resulting from current or past operations, could result in substantial costs and liabilities in the future. It is possible that new information or future developments, such as increasingly strict environmental laws, could require us to reassess our potential exposure related to environmental matters. Although we do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations, we cannot assure you that the development or discovery of new facts or conditions will not cause us to incur significant costs. As this information becomes available, or other relevant developments occur, we will make accruals accordingly. For a summary of our significant environmental-related accruals, please read Note 2 of the Notes to Combined Financial Statements of Duncan Energy Partners Predecessor included elsewhere in this prospectus.

We have ongoing programs designed to keep our pipelines and storage facility in compliance with environmental and safety requirements, and we believe that our facilities are in material compliance with the applicable regulatory requirements. As of June 30, 2006, we had a reserve of approximately $0.2 million included in other current liabilities for remediation of ground contamination related to the Acadian Gas system. Below is a discussion of the material environmental laws and regulations that relate to our business.

Specific Environmental Laws and Regulations

Pipelines. Pursuant to the Pipeline Safety Improvement Act of 2002, the DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to perform ongoing assessments of pipeline integrity, identify and characterize applicable threats to pipeline segments that could impact a high consequence area, and repair and remediate the pipeline as necessary.

Several other federal and state environmental statutes and regulations may pertain specifically to the operations of our pipelines. Among these, the Hazardous Materials Transportation Act regulates materials capable of posing an unreasonable risk to health, safety and property when transported in commerce, and the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act authorize the development and enforcement of regulations governing pipeline transportation of natural gas and NGLs. Although federal jurisdiction is exclusive over regulated pipelines, the statutes allow states to impose additional requirements for intrastate lines if compatible with federal programs. New Mexico, Texas and Louisiana have developed regulatory programs that parallel the federal program for the transportation of natural gas and NGLs by pipelines. For example, our intrastate gas pipelines and gas storage operations in Louisiana are subject to state regulations issued by the Louisiana Public Service Commission and the Louisiana Department of Natural Resources. Within the Louisiana Department of Natural Resources, the Office of Conservation has the authority to regulate all pipeline interconnections, transportation and construction or abandonment of facilities, and the Office of Pipeline Safety monitors the implementation of the DOT and Louisiana pipeline safety regulations.

Solid Waste. The operations of our pipelines may generate both hazardous and nonhazardous solid wastes that are subject to the requirements of the Resource Conservation and Recovery Act and its regulations, and other federal and state statutes and regulations. Further, it is possible that some wastes that are currently classified as nonhazardous, via exemption or otherwise, perhaps including wastes currently generated during pipeline operations, may, in the future, be designated as “hazardous wastes,” which would then be subject to more rigorous and costly treatment, storage, transportation and disposal requirements. Such changes in the regulations may result in additional expenditures or operating expenses for us.

Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and comparable state statutes, also known as “Superfund” laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that cause or contribute to the release of a “hazardous substance” into the environment. These persons include the current owner or operator

108

of a site, the past owner or operator of a site, and companies that transport, dispose of, or arrange for the disposal of the hazardous substances found at the site. CERCLA also authorizes the Environmental Protection Agency or state agency, and in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently encompasses crude oil, refined petroleum products, natural gas and NGLs, we may nonetheless handle “hazardous substances,” within the meaning of CERCLA or similar state statutes, in the course of our ordinary operations.

Air. Our operations may be subject to the Clean Air Act and other federal and state statutes and regulations that impose certain pollution control requirements with respect to air emissions from operations, particularly in instances where a company constructs a new facility or modifies an existing facility. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. However, we do not believe these requirements will have a material adverse affect on our operations.

Water. The Federal Water Pollution Control Act imposes strict controls against the unauthorized discharge of pollutants, including produced waters and other oil and natural gas wastes, into navigable waters. It provides for civil and criminal penalties for any unauthorized discharges of oil and other substances and, along with the Oil Pollution Act of 1990, or OPA, imposes substantial potential liability for the costs of oil or hazardous substance removal, remediation and damages. Similarly, the OPA imposes liability for the discharge of oil into or upon navigable waters or adjoining shorelines. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of an unauthorized discharge of pollutants into state waters.

Worker Safety and Hazard Communication. We are subject to the requirements of the Occupational Safety and Health Act, or OSHA, and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. OSHA, the Emergency Planning and Community Right-to-Know Act and comparable state statutes require those entities that operate facilities for us to organize and disseminate information to employees, state and local organizations, and the public about the hazardous materials used in its operations and its emergency planning.

Regulation of Operations

Regulation of Our Intrastate Natural Gas Pipelines and Services

At the federal level, our gas pipelines and gas storage facilities are subject to regulations of the FERC under the Natural Gas Policy Act of 1978, or the NGPA. Our natural gas intrastate systems provide transportation and storage pursuant to Section 311 of the NGPA and Section 284 of the FERC’s regulations. Under Section 311 of the NGPA, an intrastate pipeline company may transport gas for an interstate pipeline company or any local distribution company served by an interstate pipeline. We are required to provide these services on an open and nondiscriminatory basis and to make certain rate and other filings and reports in compliance with the regulations. The rates for Section 311 service can be established by the FERC or the respective state agency. The associated rates may not exceed a fair and equitable rate and are subject to challenge.

In the past, the FERC has approved market-based rates for Section 311 storage service for the storage facility in Louisiana. Recently, we filed petitions for each of our Acadian and Cypress pipelines requesting approval of increased rates for interruptible transportation service performed under Section 311, to be effective October 1, 2006, subject to refund. Each of these petitions was protested by a single shipper. We did not place the proposed rates for the Acadian and Cypress pipelines into effect on October 1, 2006. Therefore, there are no currently effective rates that are subject to refund, although the currently effective rates remain subject to complaint by all shippers. We are currently engaged in settlement discussions with the shipper and the FERC staff to establish the proposed rates for the Acadian and Cypress pipelines. Any settlement agreement between the parties must be approved by the FERC. The Louisiana Public Service Commission also reviews and approves rates for pipelines providing Section 311 service in Louisiana. For example, the Louisiana Public

109

Service Commission regulates Acadian Gas’s city gate sales. We also have a natural gas underground storage facility in Louisiana that is subject to state regulation. In addition to the above-regulations, the natural gas industry has historically been subject to numerous other forms of federal, state and local regulation.

Regulation of Our Petrochemical Pipeline Services

Our interstate Lou-Tex and Sabine propylene pipelines are common carrier pipelines regulated by the Surface Transportation Board or STB under the current version of the ICA. The ICA and its implementing regulations give the STB authority to regulate the rates we charges for service on the propylene pipelines and generally require that our rates and practices be just and reasonable and nondiscriminatory.

The majority of the natural gas pipelines in the Acadian Gas system are intrastate common carrier pipelines that are subject to various Louisiana state laws and regulations that affect the rates it charges and the terms of service. We also have a natural gas underground storage facility in Louisiana that is subject to state regulations.

For additional information regarding the potential impact of federal, state or local regulatory measures on our business, please read “Risk Factors.”

Title to Properties

Our real property holdings fall into two basic categories: (1) parcels that we own in fee, such as the land and underlying storage caverns at Mont Belvieu, Texas and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. The fee sites upon which our major facilities are located have been owned by us or our predecessors in title for many years without any material challenge known to us relating to title to the land upon which the assets are located, and we believe that we have satisfactory title to such fee sites. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way or license held by us or to our title to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way and licenses.

Legal Proceedings

On occasion, we are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. Although we are insured against various business risks to the extent we believe is prudent, the nature and amount of such insurance may not be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activity.

In 1997, Acadian Gas, along with numerous other energy companies, were named defendants in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. The plaintiff in this case seeks royalties that he contends the government should have received had the volume and heating value been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). On October 20, 2006, the U.S. District Court dismissed all of Grynberg’s claims with prejudice.

We are not aware of any other significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.

110

MANAGEMENT

General

As is commonly the case with publicly traded limited partnerships, we do not directly employ any of the persons responsible for the management or operations of our business. These functions are performed by the employees of EPCO pursuant to an administrative services agreement under the direction of the Board of Directors and executive officers of our general partner. For a description of the administrative services agreement, please read “Certain Relationships and Related Party Transactions.”

Our general partner is liable for all debts we incur (to the extent not paid by us), except to the extent that such indebtedness or other obligations are non-recourse to our general partner. Whenever possible, our general partner intends to make any such indebtedness or other obligations non-recourse to itself and its general partner.

Governance Matters

We are committed to sound principles of governance. Such principles are critical for us to achieve our performance goals, and maintain the trust and confidence of investors, employees, suppliers, business partners and stakeholders. The following is a brief description of certain existing practices we use to maintain strong governance principles.

Independence of Board Members. A key element for strong governance is independent members of the board of directors. Pursuant to the NYSE listing standards, a director will be considered independent if the board determines that he or she does not have a material relationship with our general partner or us (either directly or as a partner, unitholder or officer of an organization that has a material relationship with Enterprise Products GP or us). Based on the foregoing, the Board has affirmatively determined that , and are “independent” directors under the NYSE rules.

Heightened Independence for Audit and Conflicts Committee Members. As required by the Sarbanes-Oxley Act of 2002, the SEC adopted rules that direct national securities exchanges and associations to prohibit the listing of securities of a public company if members of its audit committee do not satisfy a heightened independence standard. In order to meet this standard, a member of an audit committee may not receive any consulting fee, advisory fee or other compensation from the public company other than fees for service as a director or committee member and may not be considered an affiliate of the public company. Neither our general partner nor any individual member of its Audit and Conflicts Committee has relied on any exemption in the NYSE rules to establish such individual’s independence. Based on the foregoing criteria, the Board of Directors of our general partner has affirmatively determined that all members of its Audit and Conflicts Committee satisfy this heightened independence requirement.

Audit Committee Financial Expert. An audit committee plays an important role in promoting effective corporate governance, and it is imperative that members of an audit committee have requisite financial literacy and expertise. As required by the Sarbanes-Oxley Act of 2002, SEC rules require that a public company disclose whether or not its audit committee has an “audit committee financial expert” as a member. An “audit committee financial expert” is defined as a person who, based on his or her experience, satisfies all of the following attributes:


	•	An understanding of generally accepted accounting principles and financial statements.

	•	An ability to assess the general application of such principles in connection with the accounting for estimates, accruals, and reserves.

	•	Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and level of complexity of issues that can reasonably be expected to be raised by our financial statements, or experience actively supervising one or more persons engaged in such activities.

111


	•	An understanding of internal controls and procedures for financial reporting.

	•	An understanding of audit committee functions.

Based on the information presented, the Board of Directors has affirmatively determined that satisfies the definition of “audit committee financial expert.”

Executive Sessions of Board. The Board of Directors of our general partner holds regular executive sessions in which non-management board members meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. During such executive sessions, one director is designated as the “Presiding Director,” who is responsible for leading and facilitating such executive sessions. Currently, the Presiding Director is , the Chairman of the Audit and Conflicts Committee.

In accordance with the rules of the NYSE, we have designated our toll-free, confidential Hotline as the method for interested parties to communicate with the Presiding Director, alone, or with the non-management Directors of our general partner as a group. All calls to this Hotline are reported to the Chairman of the Audit and Conflicts Committee of our general partner, who is responsible for communicating any necessary information to the other non-management directors as a group. The number of our confidential Hotline is . The Hotline is operated by The Network, an independent contractor that specializes in providing feedback and reporting services to more than 1,000 companies in a variety of industries.

Committees of Board of Directors

The Board of Directors of our general partner has two committees, the Audit and Conflicts Committee and the Governance Committee, which are described in the following sections:

Audit and Conflicts Committee

In accordance with NYSE rules and Section 3(a)(58)(A) of the Exchange Act, the Board of Directors of our general partner has named three of its members to serve on its Audit and Conflicts Committee. The members of the Audit and Conflicts Committee are independent directors, free from any relationship with us or any of our subsidiaries that would interfere with the exercise of independent judgment.

The members of the Audit and Conflicts Committee must have a basic understanding of finance and accounting and be able to read and understand fundamental financial statements, and at least one member of the committee shall have accounting or related financial management expertise. The members of the Audit and Conflicts Committee are , and , Chairman. The primary responsibilities of the Audit and Conflicts Committee include:


	•	monitoring the integrity of our financial reporting process and related systems of internal control;

	•	ensuring our legal and regulatory compliance and that of our general partner;

	•	overseeing the independence and performance of our independent public accountants;

	•	approving all services performed by our independent public accountants;

	•	providing for an avenue of communication among the independent public accountants, management, internal audit function and the Board of Directors;

	•	encouraging adherence to and continuous improvement of our policies, procedures and practices at all levels; and

	•	reviewing areas of potential significant financial risk to our businesses.

Under our partnership agreement, the Audit and Conflicts Committee also has the authority to review specific matters as to which the Board of Directors believes there may be a conflict of interests in order to determine if the resolution of such conflict proposed by our general partner is fair and reasonable to us. Any matters approved by the Audit and Conflicts Committee are conclusively deemed to be fair and reasonable to

112

our business, approved by all of our partners and not a breach by our general partner or its Board of Directors of any duties they may owe us or our unitholders.

Pursuant to its formal written charter adopted in , 2006, the Audit and Conflicts Committee has the authority to conduct any investigation appropriate to fulfilling its responsibilities, and it has direct access to our independent public accountants as well as any EPCO personnel whom it deems necessary in fulfilling its responsibilities. The Audit and Conflicts Committee has the ability to retain, at our expense, special legal, accounting or other consultants or experts it deems necessary in the performance of its duties.

Governance Committee

The Governance Committee of our general partner’s Board of Directors is comprised of the three independent directors ( , and , Chairman). The Governance Committee is appointed by the Board to assist the Board in fulfilling its oversight responsibilities. The Governance Committee’s primary duties and responsibilities are to develop and recommend to the Board a set of governance principles applicable to us, review the qualifications of candidates for Board membership, screen and interview possible candidates for Board membership and communicate with members of the Board regarding Board meeting format and procedures.

Governance Guidelines

Governance guidelines, together with committee charters, provide the framework for effective governance. The Board of Directors of our general partner has adopted the Governance Guidelines of Duncan Energy Partners, which address several matters, including qualifications for directors, responsibilities of directors, retirement of directors, the composition and responsibility of committees, the conduct and frequency of board and committee meetings, management succession, director access to management and outside advisors, director compensation, director orientation and continuing education, and annual self-evaluation of the board. The Board of Directors of our general partner recognizes that effective governance is an on-going process, and thus, the Board will review the Governance Guidelines of Duncan Energy Partners annually or more often as deemed necessary.

Code of Conduct

Our general partner has adopted a “Code of Conduct” that applies to all directors, officers and employees. This code sets out our requirements for compliance with legal and ethical standards in the conduct of our business, including general business principles, legal and ethical obligations, compliance policies for specific subjects, obtaining guidance, the reporting of compliance issues and discipline for violations of the code.

Code of Ethics

Our general partner has adopted a code of ethics, the “Code of Ethical Conduct for Senior Financial Officers and Managers,” that applies to our CEO, CFO, Principal Accounting Officer and senior financial and other managers. In addition to other matters, this code of ethics establishes policies to prevent wrongdoing and to promote honest and ethical conduct, including ethical handling of actual and apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting violations of the code.

Web Access

We provide access through our website at www.deplp.com to current information relating to governance, including the Audit and Conflicts Committee Charter, the Governance Committee Charter, the Code of Ethical Conduct for Senior Financial Officers and Managers, the Governance Guidelines of Duncan Energy Partners and other matters impacting our governance principles. You may also contact our investor relations department at (713) 381- for printed copies of these documents free of charge.

113

Indemnification of Directors and Officers

Under our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events any director or officer, or while serving as director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person who is or was an employee (other than an officer) or agent of our partnership.

Directors and Executive Officers

The following table sets forth the name, age and position of each of the directors and executive officers of our general partner at October 31, 2006. Each member of the Board of Directors of our general partner serves until such member’s death, resignation or removal. The executive officers of our general partner are elected for one-year terms and may be removed, with or without cause, only by the Board of Directors. Our unitholders do not elect the officers or directors of our general partner. Dan. L. Duncan, through his indirect control of our general partner, has the ability to elect, remove and replace at any time, all of the officers and directors of our general partner. Each of the individuals listed below, including Mr. Duncan, is an executive officer of our general partner.


Name	Age		Position with DEP Holdings

Dan L. Duncan		73	Director and Chairman
Richard H. Bachmann		53	Director, President and Chief Executive Officer
Michael A. Creel		52	Director, Executive Vice President and Chief Financial Officer
Gil H. Radtke		45	Director, Senior Vice President and Chief Operating Officer
W. Randall Fowler		50	Director, Senior Vice President and Treasurer
Michael J. Knesek		52	Senior Vice President, Principal Accounting Officer and Controller

Because we are a limited partnership and meet the definition of a “controlled company” under the listing standards of the NYSE, we are not required to comply with certain requirements of the NYSE. Accordingly, we have elected to not comply with Section 303A.01 of the NYSE Listed Company Manual, which would require that the Board of Directors of our general partner be comprised of a majority of independent directors. In addition, we have elected to not comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require that the Board of Directors of our general partner maintain a Nominating Committee and a Compensation Committee, each consisting entirely of independent directors.

Dan L. Duncan was elected Chairman and a Director of our general partner in October 2006, Chairman and a Director of EPE Holdings in August 2005 and Chairman and a Director of Enterprise Products GP in April 1998. Mr. Duncan has served as Chairman and a Director of the general partner of Enterprise Products OLP in December 2003 and as Chairman of EPCO since 1979.

Richard H. Bachmann was elected President, Chief Executive Officer and a Director of our general partner in October 2006 and a Director of EPE Holdings, Enterprise Products GP and TEPPCO GP in February 2006. Mr. Bachmann previously served as a Director of Enterprise Products GP from June 2000 to January 2004. Mr. Bachmann was elected Executive Vice President, Chief Legal Officer and Secretary of Enterprise Products GP and of EPCO, and a Director of EPCO, in January 1999. In October 2006, Mr. Bachmann was nominated to be an independent manager of Constellation Energy Partners LLC.

Michael A. Creel was elected Executive Vice President, Chief Financial Officer and a Director of our general partner in October, 2006. Also, he was elected Executive Vice President of Enterprise Products GP and EPCO in January 2001, after serving as a Senior Vice President of Enterprise Products GP and EPCO from November 1999 to January 2001. Mr. Creel, a certified public accountant, served as Chief Financial Officer of

114

EPCO from June 2000 through April 2005 and was named Chief Operating Officer of EPCO in April 2005. In June 2000, Mr. Creel was also named Chief Financial Officer of Enterprise Products GP. Mr. Creel has served as a Director of the general partner of Enterprise Products OLP since December 2003, and has served as President, Chief Executive Officer and a Director of EPE Holdings since August 2005. Mr. Creel was elected a Director of Edge Petroleum Corporation (a publicly traded oil and natural gas exploration and production company) in October 2005 and a Director of Enterprise Products GP and TEPPCO GP in February 2006.

Gil H. Radtke was elected Senior Vice President, Chief Operating Officer and a Director of our general partner in October, 2006 and Senior Vice President of Enterprise Products GP in February 2002. Mr. Radtke joined Enterprise Products Partners in connection with their purchase of Diamond-Koch’s storage and propylene fractionation assets in January and February 2002. Before joining Enterprise Products Partners, Mr. Radtke served as President of the Diamond-Koch joint venture from 1999 to 2002, where he was responsible for its storage, propylene fractionation, pipeline and NGL fractionation businesses.

W. Randall Fowler was elected Senior Vice President, Treasurer and a Director of our general partner in October 2006 and a Director of EPE Holdings, Enterprise Products GP and TEPPCO GP in February 2006. Mr. Fowler was elected Senior Vice President and Treasurer of Enterprise Products GP in February 2005 and Chief Financial Officer of EPCO in April 2005. Mr. Fowler, a certified public accountant (inactive), joined Enterprise Products Partners as Director of Investor Relations in January 1999 and served as Treasurer and a Vice President of Enterprise Products GP and EPCO from August 2000 to February 2005. Mr. Fowler has served as Senior Vice President and Chief Financial Officer of EPE Holdings since August 2005.

Michael J. Knesek, a certified public accountant, was elected Senior Vice President, Principal Accounting Officer and Controller of our general partner in October, 2006. He was also elected Senior Vice President and Principal Accounting Officer of Enterprise Products GP in February 2005. Previously, Mr. Knesek served as Principal Accounting Officer and a Vice President of Enterprise Products GP from August 2000 to February 2005. Mr. Knesek has served as Senior Vice President and Principal Accounting Officer of EPE Holdings since August 2005. Mr. Knesek has been the Controller and a Vice President of EPCO since 1990.

Executive Compensation

We do not directly employ any of the persons responsible for managing or operating our business. Instead, we are managed by our general partner, DEP Holdings, the executive officers of which are employees of EPCO. Our reimbursement for the compensation of executive officers is governed by the administrative services agreement with EPCO. Please read “Certain Relationships and Related Party Transactions” for a description of the administrative services agreement.

Compensation Committee Interlocks and Insider Participation

As stated above, the compensation of the executive officers of our general partner is paid by EPCO, and we reimburse EPCO for that portion of its compensation expense that is related to our business, pursuant to the administrative services agreement. No compensation expense is borne by us with respect to Mr. Duncan.

Commitments under Equity Compensation Plans of EPCO

Under the administrative services agreement, we reimburse EPCO for the compensation of all operations personnel it employs on our behalf. This includes the costs attributable to equity-based awards granted to these personnel to the extent our Board adopts an equity-based plan for our common units. When these employees exercise unit options, we reimburse EPCO for the difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units awarded to the employee. We may reimburse EPCO for these costs by either furnishing cash, reissuing treasury units or by issuing new units.

115

Compensation of Directors of DEP Holdings

Neither we nor DEP Holdings, our general partner, provide any additional compensation to employees of EPCO who serve as directors of our general partner. The employees of EPCO currently serving as directors are Messrs. Duncan, Bachmann, Creel, Radtke, and Fowler.

At , 2006, our independent directors are Messrs. , and . Our general partner is responsible for compensating these directors for their services. Its standard compensation arrangement is as follows:


	•	Each independent director receives $50,000 in cash annually.

	•	If the individual serves as chairman of a committee of the Board of Directors, then he receives an additional $7,500 in cash annually.

116

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information regarding the beneficial ownership of our common units prior to and as of the closing of this offering by:


	•	each person known by our general partner to beneficially own more than 5% of our common units;

	•	each of the named executive officers of our general partner;

	•	all of the current directors of our general partner; and

	•	all of the current directors and executive officers of our general partner as a group.

All information with respect to beneficial ownership has been furnished by the respective directors or officers, as the case may be. Each person has sole voting and dispositive power over the common units shown unless otherwise indicated below.


	Common Units					Common Units
	Beneficially Owned					Beneficially Owned
	Prior to Offering					After Offering
Name of Beneficial Owner:	Units		Percent			Units		Percent

Enterprise Products OLP(1)		0		100	%		7,298,551		36.0	%

Dan L. Duncan(1)(2)		0		0	%		7,298,551		36.0	%
Richard H. Bachmann		0		0	%		0		0	%
Michael A. Creel		0		0	%		0		0	%
Gil H. Radtke		0		0	%		0		0	%
W. Randall Fowler		0		0	%		0		0	%
Michael J. Knesek		0		0	%		0		0	%
All directors and executive officers as a group (6 persons)		0		100	%		7,298,551		36.0	%


(1)		Prior to this offering, Enterprise Products OLP owned a 98% limited partner interest in us. In connection with the closing of this offering and the contribution of assets by Enterprise Products OLP to us, we will issue to Enterprise Products OLP 7,298,551 common units representing approximately 36.0% of the outstanding common units at the closing of this offering (or approximately 26.3% if the underwriters’ option to purchase additional units is exercised in full).

(2)		Includes common units owned by Enterprise Products OLP, for which Mr. Duncan disclaims beneficial ownership other than to the extent of his direct or indirect percentage interest in Enterprise Products OLP.

117

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Our Relationship with EPCO and Enterprise Products Partners

We have an extensive and ongoing relationship with EPCO and their other affiliates, which include the following significant entities:


	•	EPCO and its private company subsidiaries;

	•	our general partner; and

	•	Enterprise Products Partners, Enterprise GP Holdings and TEPPCO and their respective general partners, which are controlled by affiliates of EPCO.

Unless noted otherwise, our agreements with EPCO, Enterprise Products Partners and their affiliates 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 owned in part and controlled by Dan L. Duncan, who is also a director and Chairman of our general partner, EPE Holdings and Enterprise Products GP. Mr. Duncan owns 50.4% of the voting stock of EPCO. The remaining shares of EPCO capital stock are held primarily by trusts for the benefit of members of Mr. Duncan’s family.

We and our general partner are separate legal entities from EPCO and their other affiliates, with assets and liabilities that are separate from those of EPCO and their other affiliates. However, EPCO depends on the cash distributions it receives from Enterprise Products Partners (including its retained interests in our subsidiaries), Enterprise GP Holdings and other investments to fund its other operations and to meet its debt obligations.

Relationship with Enterprise Products Partners. Enterprise Products Partners was the shipper of record on our Sabine Propylene and Lou-Tex Propylene pipelines. We recorded $33.9 million, $40.9 million and $42.3 million of related party pipeline transportation revenues from Enterprise Products Partners for the years ended December 31, 2005, 2004 and 2003, respectively. We recorded $18.3 million and $19.1 million of such related party revenues during the six months ended June 30, 2006 and 2005, respectively.

Prior to 2004, Sabine Propylene was regulated by the FERC. Our Lou-Tex Propylene pipeline was also subject to the FERC’s jurisdiction until 2005. For the periods in which Sabine Propylene and Lou-Tex Propylene were subject to FERC regulations, related party revenues with Enterprise Products Partners were based on the maximum tariff rate allowed for each system. We continued to charge Enterprise Products Partners such maximum transportation rates after both entities were declared exempt from FERC oversight.

Enterprise Products Partners has entered into agreements with third parties involving use of the Sabine Propylene and Lou-Tex Propylene pipelines. Enterprise Products Partners recorded $15.4 million, $14.2 million and $15.1 million in revenues for the years ended December 31, 2005, 2004 and 2003, respectively, in connection with such agreements. Enterprise Products Partners third-party revenues from these agreements were $7.5 million and $8.5 million during the six months ended June 30, 2006 and 2005, respectively. Apart from such agreements, Enterprise Products Partners did not utilize the Sabine Propylene and Lou-Tex Propylene assets. Concurrently with the closing of this offering, Enterprise Products Partners will assign to us certain agreements with third parties involving the use of our Sabine Propylene and Lou-Tex Propylene pipelines but will remain jointly and severally liable on those agreements.

Our related party revenues from Enterprise Products Partners also include the sale of natural gas. Our natural gas sales to Enterprise Products Partners were $35.8 million, $21.7 million and $13.8 million for the years ended December 31, 2005, 2004 and 2003, respectively. Our related party operating costs and expenses

118

include the cost of natural gas Enterprise Products Partners sold to us. Such amounts were $25.3 million, $3.8 million and none for the years ended December 31, 2005, 2004 and 2003, respectively.

Our natural gas sales to Enterprise Products Partners were $28.9 million and $15.7 million during the six months ended June 30, 2006 and 2005, respectively. Our natural gas purchases from Enterprise Products Partners were $8 million and $4.7 million for the six months ended June 30, 2006 and 2005, respectively.

In addition, Enterprise Products Partners has furnished letters of credit on behalf of Evangeline’s debt service requirements. At December 31, 2005 and June 30, 2006, such outstanding letters of credit totaled $1.2 million.

We also provide underground storage services to Enterprise Products Partners for the storage of NGLs and petrochemicals. For the years ended December 31, 2005, 2004 and 2003, we recorded $17.6 million, $17 million and $17.3 million, respectively, in storage revenue from Enterprise Products Partners. Such revenues were $8.7 million and $8 million for the six months ended June 30, 2006 and 2005, respectively.

Mont Belvieu Caverns will continue to provide storage services to Enterprise Products OLP for several lines of its business, including:


	•	NGL marketing;

	•	butane isomerization;

	•	octane enhancement;

	•	propylene fractionation; and

	•	NGL fractionation.

Upon the closing of this offering, Mont Belvieu Caverns will enter into several storage service agreements with Enterprise Products OLP. The initial terms of these agreements will commence on the closing of this offering and end on December 31, 2016. These agreements include rates comparable to those rates charged to third parties with service contracts of similar size and duration.

We have participated in the Enterprise Products Partners cash management program for all periods presented.

We expect that certain commercial arrangements with Enterprise Products Partners will change once the Partnership completes its initial public offering. These changes will include:


	•	Through the direct assignment of contracts, a reduction in transportation rates previously charged Enterprise Products Partners for usage of the Lou-Tex Propylene and Sabine Propylene pipelines to the levels Enterprise Products Partners realizes from third-party shippers on these systems. On an unaudited pro forma basis, the expected reduction in combined revenues would be $10.8 million for the six months ended June 30, 2006 and $18.4 million for the year ended December 31, 2005.

	•	An increase in storage fees charged Enterprise Products Partners by Mont Belvieu Caverns related to the storage activities of Enterprise Products Partners’ octane enhancement, isomerization and NGL and petrochemical marketing businesses. Historically, such intercompany charges were below market and eliminated in the consolidated revenues and costs and expenses of Enterprise Products Partners. Prospectively, such rates will be market-related. On an unaudited pro forma basis, the expected increase in combined revenues would be $6.2 million for the six months ended June 30, 2006 and $11.6 million for the year ended December 31, 2005.

	•	In connection with storage agreements for a variety of products which will be entered into between Enterprise Products Partners and Mont Belvieu Caverns concurrently with the closing of this offering Enterprise Products Partners will agree to the allocation of all storage well measurement gains and losses relating to these products. In addition, the limited liability company agreement for Mont Belvieu Caverns will specially allocate to Enterprise Products Partners any items of income and gain or loss and deduction relating to measurement losses and measurement gains, including amounts that Mont Belvieu

119


		Caverns may retain or deduct as handling losses. Enterprise Products Partners will also be required to contribute cash to Mont Belvieu Caverns, or will be entitled to receive distributions from Mont Belvieu Caverns, based on the then-current net measurement gains or measurement losses. As a result, we will continue to record measurement gains and losses associated with the operation of our Mont Belvieu storage facility after the closing date of this offering on a consolidated basis as operating costs and expenses. However, these measurement gains and losses should not affect our net income or have a significant impact on us with respect to our cash flows from operating activities and, accordingly, no reserve account will be established by us for measurement losses on our balance sheet. On an unaudited pro forma basis, the expected decrease in operating costs and expenses would be is $0.2 million for the six months ended June 30, 2006 and $3.1 million for the year ended December 31, 2005. The pro forma decrease in operating costs and expenses reflects the removal of historical net measurement losses.

Relationships with TEPPCO Partners

Currently, Enterprise Products OLP provides storage services to TE Products Pipeline Company, a subsidiary of TEPPCO Partners. The initial term of this storage agreement ends December 15, 2006 but will continue month to month thereafter unless cancelled by either party. Concurrently with the closing of this offering, Enterprise Products OLP will assign this agreement to Mont Belvieu Caverns. This agreement includes rates comparable to rates charged to third parties with contracts of similar size and duration.

Relationships with Unconsolidated Affiliate

We sell natural gas to Evangeline, which, in turn, uses such natural gas to satisfy its sales commitments to Entergy Louisiana. Our sales of natural gas to Evangeline totaled $331.5 million, $241.4 million and $214.2 million for the years ended December 31, 2005, 2004 and 2003, respectively. Our sales of natural gas to Evangeline totaled $151.4 million and $127.4 million during the six months ended June 30, 2006 and 2005, respectively.

Additionally, we have a service agreement with Evangeline whereby we provide Evangeline with construction, operations, maintenance and administrative support related to its pipeline system. Evangeline paid us $0.4 million, $0.5 million and $0.4 million for such services during the years ended December 31, 2005, 2004 and 2003, respectively. Evangeline paid us $0.3 million and $0.2 million during the six months ended June 30, 2006 and 2005, respectively.

Contribution, Conveyance and Assumption Agreement

Pursuant to a Contribution, Conveyance and Assumption Agreement, Enterprise Products Partners, Enterprise Products OLP and their affiliates, and we and our operating partnership, have agreed to contribute to us 66% of the equity interests in Mont Belvieu Caverns, Acadian Gas, Sabine Propylene, Lou-Tex Propylene and South Texas NGL.

As consideration for these assets and agreements, including the reimbursement to us for capital expenditures, we have agreed to distribute an aggregate cash amount equal to (1) $200 million plus (2) the net proceeds to us from this offering (after giving effect to underwriting discounts and commissions, the structuring fee and estimated net offering expenses of $2.0 million) minus (3) (a) $68.6 million minus (b) all construction and acquisition costs paid prior to the closing time of this initial public offering with respect to the South Texas NGL Pipeline (excluding the original purchase costs of approximately $97.7 million) and to issue 13,000,000 common units, representing approximately 36.0% of the common units to be outstanding immediately after this offering and a 2% general partner interest to Enterprise Products OLP.

As partial consideration for these assets and agreements, we have also granted Enterprise Products Partners a right of first refusal on the equity interests in our operating subsidiaries and a right of first refusal on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business.

120

Omnibus Agreement

Upon the closing of this offering, we will enter into an Omnibus Agreement with Enterprise Products Partners and its affiliates that will govern our relationship with them on the following matters:


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

	•	reimbursement of certain expenditures for South Texas NGL.

Indemnification for Environmental and Related Liabilities

Enterprise Products Partners agreed to indemnify us after the closing of our initial public offering against certain environmental and related liabilities arising out of or associated with the operation of the assets before the closing date of our initial public offering. These liabilities include both known and unknown environmental and related liabilities. This indemnification obligation will terminate three years after the closing of our initial public offering. There is an aggregate cap of $15.0 million on the amount of indemnity coverage. In addition, we are not entitled to indemnification until the aggregate amounts of claims exceed $250,000. Liabilities resulting from a change of law after the closing of our initial public offering are excluded from the environmental indemnity by Enterprise Products Partners for the unknown environmental liabilities.

Enterprise Products Partners will also indemnify us for liabilities related to:


	•	certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to us in connection with our initial public offering are located and failure to obtain certain consents and permits necessary to conduct our business that arise within three years after the closing of our initial public offering; and

	•	certain income tax liabilities attributable to the operation of the assets contributed to us in connection with our initial public offering prior to the time they were contributed.

Reimbursement for Certain Expenditures Attributable to South Texas NGL

Enterprise Products Partners has agreed to make additional contributions to us as reimbursement for our 66% share of excess construction costs, if any, above the current estimated capital expenditures to complete planned expansions on the South Texas NGL pipeline. We currently estimate the costs to complete planned expansions of the South Texas NGL pipeline after the closing of this initial public offering will be approximately $30.9 million, of which our 66% share will be approximately $20.4 million. We will retain cash in an amount equal to our share of these estimated costs from the proceeds of this offering in order to fund our share of the planned expansion costs. Enterprise Products Partners will also make a capital contribution to South Texas NGL for its 34% interest upon a capital call from South Texas NGL.

Amendments

The omnibus agreement may not be amended without the prior approval of the conflicts committee if the proposed amendment will, in the reasonable discretion of our general partner, adversely affect holders of our common units.

Competition

Neither Enterprise Products Partners nor any of its affiliates will be restricted under the omnibus agreement from competing with us. Except as otherwise expressly agreed in the administrative services agreement, Enterprise Products Partners and any of its affiliates may acquire, construct or dispose of additional midstream or other assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. These agreements are in addition to other agreements relating to business opportunities and potential conflicts of interest set forth on our administrative services agreement with Enterprise Products Partners, EPCO and other affiliates of EPCO. Please read “ — Administrative Services Agreement” below.

121

Mont Belvieu Caverns Limited Liability Company Agreement

Provisions relating to Measurement Gains and Losses. The limited liability company agreement of Mont Belvieu Caverns will specially allocate any items of income and gain or loss and deduction relating to net measurement losses and measurement gains to Enterprise Products OLP. Measurement gains means items of Mont Belvieu Caverns’ income or gain relating to the return by Mont Belvieu Caverns to customers of natural gas, natural gas liquids or other products measured into storage, including amounts that Mont Belvieu Caverns may retain or deduct as handling losses on such product transferred into storage. Measurement losses means items of Mont Belvieu Caverns’ loss or deduction relating to the return by Mont Belvieu Caverns to customers of natural gas, natural gas liquids or other products measured into storage. Net measurement gains or measurement losses shall be calculated on an aggregate basis from the closing date of this offering through the applicable measurement date.

Within 10 days following any notice by Mont Belvieu Caverns’ general partner of any net measurement losses as of the end of any month, Enterprise Products OLP will be required to contribute cash to Mont Belvieu Caverns in an amount equal to any net measurement losses set forth in such notice. In the event Enterprise Products OLP fails to make a required contribution, Mont Belvieu Caverns may withhold distributions, will have a lien on the partnership interest of Enterprise Products OLP and charge Enterprise Products OLP for costs and any applicable interest incurred in connection with the funding of the required contribution amount.

Within 45 days following the end of any fiscal quarter, Mont Belvieu Caverns will distribute to Enterprise Products OLP a cash amount equal to any net measurement gains. To the extent practicable and requested by Enterprise Products OLP, Mont Belvieu Caverns and Enterprise Products OLP will also establish reasonable procedures for prompt distribution from time to time of any net measurement gains prior to 45 days following the end of any fiscal quarter.

Mont Belvieu Caverns Expansion Capital Agreements. Pursuant to the Mont Belvieu Caverns limited liability company agreement, Enterprise Products OLP may, in its sole discretion, fund any portion of the costs related to potential expansion projects. We are currently contemplating expansion projects at Mont Belvieu Caverns, which may include new entries into existing wells, the conversion of existing wells to store natural gas and the installation of new piping and certain related facilities, which may be commenced during 2007 in the range of $25 to $75 million. Additional expenditures of up to $200 million may be made during 2008 and 2009.

The Mont Belvieu Caverns limited liability company agreement will provide that:


	•	We and Enterprise Products OLP will share in revenue from Mont Belvieu Caverns based on a formula which takes into account the total deemed capital contributed by each to Mont Belvieu Caverns. As of the closing date of this offering, the amount contributed by each of us and Enterprise Products OLP will be based on the relative percentage interests of the parties and the book value of capital expenditures made through the closing date of this offering, including projects for expansions or other capital expenditures made to Mont Belvieu Caverns prior to the closing of this offering. After the closing date of this offering, Enterprise Products OLP may, in its sole discretion, fund the Mont Belvieu Expansion costs as set forth below.

	•	With respect to future expansions to Mont Belvieu Caverns, each party to the agreement can contribute to such additional expansions up to its respective sharing ratio. To the extent one party decides not to participate in the additional expansion, then the other party may fund the expansion and receive a corresponding increase in its sharing ratio. However, from the date any expenditures are made by Enterprise Products OLP and not the other parties for Mont Belvieu Expansion costs until the date that any pipeline or storage portion of any Mont Belvieu Expansion is placed in service and written notice of such placement into service is given by the general partner to Enterprise Products OLP (the “Initial Commencement Date”), we will remain entitled to distributions from Mont Belvieu Caverns in accordance with our initial sharing ratios, and Enterprise Products OLP will not be entitled to any additional distributions other than its initial sharing ratio. Upon the Initial Commencement Date and

122


		until 90 days thereafter, Enterprise Products OLP will be entitled to receive 100% of the incremental cash flow of Mont Belvieu Caverns which is generated by the incremental revenue attributable to those portions of the storage or pipeline portions of Mont Belvieu Expansion which have been placed in service and funded by Enterprise Products OLP, but Enterprise Products OLP will not be entitled to any other distributions which do not relate to such incremental cash flow. If we do not reimburse Enterprise Products OLP (or make a contribution to Mont Belvieu Caverns and cause Mont Belvieu Caverns to reimburse Enterprise Products OLP) for an amount equal to (i) (A) the amount of contributions made by Enterprise Products OLP for Mont Belvieu Expansion costs plus (B) the effective cost of capital to Enterprise Products OLP (based on weighted average interest rate of Enterprise Products OLP incurred for borrowings made during such period until payment is made to Enterprise Products OLP, less (C)) any amounts received by Enterprise Products OLP in accordance with the foregoing provisions for incremental cash flow generated by the Mont Belvieu Expansion which have been placed in service and funded by Enterprise Products OLP, multiplied by (ii) its sharing ratio, on or before the date 90 days after the Initial Commencement Date, the sharing ratios of the parties shall be adjusted.


	•	If we fund our portion of additional Mont Belvieu Expansion expenditures (or any other expenditures for which a contribution of partners is made) and Enterprise Products OLP fails to contribute its portion, the sharing ratios shall be adjusted at the time such contribution is made.

Administrative Services Agreement

At or prior to the closing of this offering, we and our general partner will become party to the existing administrative services agreement with EPCO, Enterprise Products Partners and its general partner, Enterprise GP Holdings and its general partner, TEPPCO Partners and its general partner, and certain affiliated entities. We have no employees. All of our operating functions are performed by employees of EPCO pursuant to the administrative services agreement. EPCO also provides general and administrative support services to us in accordance with the administrative services agreement. The significant terms of the administrative services agreement are as follows:


	•	EPCO provides administrative, management, engineering and operating services as may be necessary to manage and operate our businesses, properties and assets (in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services. Certain employees who perform services for South Texas NGL and Mont Belvieu Caverns are also dedicated by EPCO for such services.

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

	•	EPCO allows us to participate as named insureds in its overall insurance program with the associated premiums and related costs being allocated to us. We reimbursed EPCO $1.7 million, $2.3 million and $2.2 million for insurance costs for the years ended December 31, 2005, 2004 and 2003, respectively.

Our operating costs and expenses for the years ended December 31, 2005, 2004 and 2003 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Our reimbursements to EPCO for operating costs and expenses were $35.7 million, $25.6 million and $25.3 million for the years ended December 31, 2005, 2004 and 2003, respectively. Such reimbursements were $16.6 million and $16.4 million for the six months ended June 30, 2006 and 2005, respectively.

123

office supplies) or (ii) based on an allocation of such charges between the various parties to administrative services agreement based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). Our reimbursements to EPCO for general and administrative costs were $3.9 million, $4.2 million and $4.9 million for the years ended December 31, 2005, 2004 and 2003, respectively. Our reimbursements to EPCO for general and administrative costs were $1.7 million and $1.9 million during the six months ended June 30, 2006 and 2005, respectively.

A small number of key employees devote a portion of their time to our operations and affairs and participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of restricted units of Enterprise Products Partners and limited partner interests in EPE Unit L.P. The amount of equity-based compensation allocable to our businesses was $26 thousand for the year ended December 31, 2005 and $29 thousand for the six months ended June 30, 2006. Such amounts are immaterial to our combined financial position, results of operations and cash flows.

The administrative services agreement addresses potential conflicts that may arise among us and our general partner, Enterprise Products Partners and its general partner, Enterprise GP Holdings and its general partner, and the EPCO Group, which includes EPCO and its affiliates (but does not include the aforementioned entities and their controlled affiliates) The administrative services agreement provides, among other things, that:


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


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

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

Enterprise GP Holdings will be presumed to desire to acquire the equity securities until such time as its general partner advises the EPCO Group, Enterprise Products GP and us that it has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to exceed $100 million, the decision to decline the acquisition will be made by the Chief Executive Officer of EPE Holdings after consultation with and subject to the approval of the Audit and Conflicts Committee of EPE Holdings. If the purchase price is reasonably likely to be less than such threshold amount, the Chief Executive Officer of EPE Holdings may make the determination to decline the acquisition without consulting the Audit and Conflicts Committee of EPE Holdings. In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, Enterprise Products GP and our general partner, Enterprise Products Partners will have the second right to the pursue such acquisition either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of us. In the event that Enterprise Products Partners affirmatively directs the opportunity to us, we may pursue such acquisition. Enterprise Products Partners will be presumed to desire to acquire the equity securities until such time as Enterprise Products GP advises the EPCO Group Holdings that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing Enterprise Products GP’s Chief Executive Officer and Audit and Conflicts Committee. In the event that Enterprise Products Partners abandons the acquisition for itself and for us and so notifies the EPCO Group and our general partner,

124

the EPCO Group may pursue the acquisition without any further obligation to any other party or offer such opportunity to other affiliates.


	•	if any business opportunity not covered by the preceding bullet point is presented to the EPCO Group, Enterprise GP Holdings, EPE Holdings, Enterprise Products GP, Enterprise Products Partners, our general partner or us, Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of us. Enterprise Products Partners will be presumed to desire to pursue the business opportunity until such time as Enterprise Products GP advises the EPCO Group, EPE Holdings and our general partner that Enterprise Products Partners has abandoned the pursuit of such business opportunity. In the event that the purchase price or cost associated with the business opportunity is reasonably likely to exceed $100 million, the decision to decline the business opportunity will be made by the Chief Executive Officer of Enterprise Products GP after consultation with and subject to the approval of the Audit and Conflicts Committee of Enterprise Products GP. If the purchase price or cost is reasonably likely to be less than such threshold amount, the Chief Executive Officer of Enterprise Products GP may make the determination to decline the business opportunity without consulting Enterprise Products GP’s Audit and Conflicts Committee. In the event that Enterprise Products Partners affirmatively directs the business opportunity to us, we may pursue such business opportunity. In the event that Enterprise Products Partners abandons the business opportunity for itself and for us and so notifies the EPCO Group, EPE Holdings and our general partner, Enterprise GP Holdings will have the second right to pursue such business opportunity, and will be presumed to desire to do so, until such time as EPE Holdings shall have determined to abandon the pursuit of such opportunity in accordance with the procedures described above, and shall have advised the EPCO Group that Enterprise GP Holdings has abandoned the pursuit of such acquisition. In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, the EPCO Group may pursue the business opportunity without any further obligation to any other party or offer such opportunity to other affiliates.

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

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


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

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

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

125

CONFLICTS OF INTEREST, BUSINESS OPPORTUNITY AGREEMENTS
AND FIDUCIARY DUTIES

Conflicts of Interest and Business Opportunity Agreements

General. Conflicts of interest exist and may arise in the future as a result of the relationships among us, Enterprise Products Partners, Enterprise GP Holdings, TEPPCO Partners and our and their respective general partners and affiliates. Our general partner, DEP Holdings, is controlled indirectly by Enterprise Products Partners. Through Dan L. Duncan’s indirect control of the general partners of Enterprise Products Partners, Enterprise GP Holdings, TEPPCO Partners and us, Mr. Duncan has the ability to elect, remove and replace the directors and officers of the general partners of Enterprise Products Partners, Enterprise GP Holdings, TEPPCO Partners and us. The assets of our general partner and Enterprise Products Partners, Enterprise GP Holdings, TEPPCO Partners and us overlap in certain areas, which may result in various conflicts of interest in the future.

Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our partners. Some of the executive officers and non-independent directors of our general partner also serve as executive officers or directors of the general partners of Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners. As a result, they have fiduciary duties to manage the business of Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners, respectively, in a manner beneficial to such entities and their respective partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to Enterprise Products Partners, Enterprise GP Holdings or TEPPCO Partners, on the one hand, and us, on the other hand, are in conflict.

It is not possible to predict the nature or extent of these potential future conflicts of interest at this time, nor is it possible to determine how we will address and resolve any such future conflicts of interest. However, the resolution of these conflicts may not always be in our best interest or that of our unitholders. We do not currently intend to take any action which would limit the ability of Enterprise Products Partners, Enterprise GP Holdings or TEPPCO Partners to pursue their business strategies.

Administrative Services Agreement. At or prior to the closing of this offering, we and our general partner will become party to an existing administrative services agreement with EPCO, Enterprise Products Partners, and its general partner, Enterprise GP Holdings and its general partner, TEPPCO Partners, and its general partner, and certain affiliated entities. The administrative services agreement will address potential conflicts that may arise among us and our general partner, Enterprise Products Partners and its general partner, Enterprise GP Holdings and its general partner, TEPPCO Partners and its general partner, and the EPCO Group, which includes EPCO and its affiliates (excluding us, our general partner, Enterprise Products Partners and its subsidiaries, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings, and TEPPCO Partners, its general partner and their controlled affiliates). Please read “Certain Relationships and Related Party Transactions — Administrative Services Agreement.”

Conflicts Between Our General Partner and its Affiliates and Our Partners. Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is deemed fair and reasonable to the Partnership. Any resolution shall be deemed fair and reasonable if it is:


	•	approved by a majority of the members of the audit and conflicts committee, although our general partner is not obligated to seek such approval;

	•	approved by the vote of holders of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates; or

126


	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties.

Our general partner may, but is not required to, seek the approval of such resolution from the audit and conflicts committee of its board of directors. If our general partner does not seek approval from the audit and conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies the standard set forth in the third bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or its audit and conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict, including taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires.

Conflicts of interest could arise in the situations described below, among others.

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders.

The amount of cash that is available for distribution to our unitholders is affected by decisions of our general partner regarding such matters as:


	•	amount and timing of cash expenditures (including expansion projects at Mont Belvieu or other subsidiaries that may be funded through the construction phase by Enterprise Products Partners and acquired or contributed to us at a later date);

	•	assets sales or acquisitions;

	•	borrowings;

	•	the issuance of additional common units; and

	•	the creation, reduction or increase of reserves in any quarter.

We will reimburse EPCO and its affiliates for expenses.

We will reimburse EPCO and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering staff and support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. Our general partner may do so in any manner determined by our general partner in good faith. Please read “Certain Relationships and Related Party Transactions.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

127

Unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations for the benefit of our unitholders.

Our partnership agreement allows our general partner to determine any amounts to reimburse itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are or will be the result of arm’s-length negotiations for the benefit of our unitholders.

As described in this prospectus, we will be a party to a number of agreements with our general partner and its affiliates at the time of the closing of this offering. These contracts include the administrative services agreement, storage agreements and transportation agreements.

Our general partner will determine, in good faith, the terms of any of these transactions or amendments to existing agreements entered into after the sale of the common units offered in this offering.

Our common units are subject to our general partner’s limited call right.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. At the completion of this offering and assuming no exercise of the underwriters’ option to purchase additional common units, our general partner and its affiliates will own approximately 36.0% of our outstanding common units. Please read “Description of Material Provisions of Our Partnership Agreement — Limited Call Right.”

We may not choose to retain separate counsel for ourselves or for the holders of our common units.

The attorneys, independent auditors and others who have performed services for us regarding the offering have been retained by our general partner, its affiliates and us and may continue to be retained by our general partner, its affiliates and us after the offering. Attorneys, independent auditors and others who will perform services for us in the future will be selected by our general partner or our audit and conflicts committee and may also perform services for our general partner and its affiliates. We may, but are not required to, retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, after the sale of the common units offered in this prospectus, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner’s affiliates may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement and subject to certain business opportunity agreements, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Please read “Certain Relationships and Related Party Transactions — Administrative Services Agreement.”

Shared Personnel. Our general partner will manage our operations and activities. Under the amended and restated administrative services agreement, EPCO will provide all employees and administrative,

128

operational and other services for us. All of our general partner’s executive officers will, and certain other EPCO employees assigned to our operations may, also perform services for EPCO, Enterprise Products Partners, Enterprise GP Holdings, TEPPCO Partners and their affiliates. The services performed by these shared personnel will generally be limited to non-commercial functions, including but not limited to human resources, information technology, financial and accounting services and legal services. We will adopt policies and procedures to protect and prevent inappropriate disclosure by shared personnel of commercial and other non-public information relating to us, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners.

Compensation Arrangements. Dan L. Duncan, as the control person of EPCO and the control person of our general partner and the general partners of Enterprise Products Partners, Enterprise GP Holdings, and TEPPCO Partners, is responsible for establishing the compensation arrangements for all EPCO employees, including employees who provide services to us, Enterprise Products Partners, Enterprise GP Holdings and TEPPCO Partners.

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, restrict, eliminate or otherwise modify the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. These modifications are detrimental to the unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:


State law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general

129


		partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held, including the duties of due care and loyalty.

		Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the audit and conflicts committee of the board of directors of our general partner must be:

		• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

		• “fair and reasonable” to us, which may take into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous, or unfavorable or disadvantageous, to us).

		If our general partner does not seek approval from the audit and conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the indemnitee’s conduct was unlawful.

Rights and remedies of unitholders		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

In order to become one of our limited partners, a unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of

130

partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

We are required to indemnify our general partner and its officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. This indemnification is required unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, that these persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. In the opinion of the Commission, indemnification provisions that purport to include indemnification for liabilities arising under the Securities Act are contrary to public policy and are, therefore, unenforceable. If you have questions regarding the fiduciary duties of our general partner, you should consult with your own counsel. Please read “Description of Material Provisions of Our Partnership Agreement — Indemnification.”

131

DESCRIPTION OF OUR COMMON UNITS

Our common units represent limited partner interests that entitle the holders to participate in our cash distributions and to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and our general partner in and to cash distributions, please read “Cash Distribution Policy and Restrictions on Distributions.”

We intend to apply for listing of our common units on the NYSE under the symbol “DEP.” If our common units are approved for listing, any additional common units we issue will also be listed on the NYSE.

Transfer Agent and Registrar

Mellon Investor Services LLC will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following that must be paid by unitholders:


	•	surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

	•	special charges for services requested by a holder of a common unit; and

	•	other similar fees or charges.

There will be no charge to common unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may at any time resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Units

By transfer of our common units in accordance with our partnership agreement, each transferee of our common units will be admitted as a common unitholder with respect to the units transferred when such transfer and admission is reflected in our books and records. Additionally, each transferee of our units:


	•	becomes the record holder of the units;

	•	represents that the transferee has the capacity, power and authority to enter into and become bound by our partnership agreement;

	•	automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;

	•	grants powers of attorney to the officers of our general partner and any liquidator of our partnership as signified in our partnership agreement;

	•	gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

An assignee will become a limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

132

Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

133

DESCRIPTION OF MATERIAL PROVISIONS OF OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included as Appendix A in this prospectus.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:


	•	with regard to distributions of available cash, please read “Cash Distribution Policy and Restrictions on Distributions;”

	•	with regard to fiduciary duties of our general partner, please read “Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties;”

	•	with regard to rights of holders of common units, please read “Description of Our Common Units;” and

	•	with regard to allocations of taxable income and other matters, please read “Material Tax Consequences.”

Organization and Duration

We were organized on September 29, 2006 and have a perpetual existence.

Purpose

Under our partnership agreement, we are permitted to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law and, in connection therewith, to exercise all of the rights and powers conferred upon us pursuant to the agreements relating to such business activity; provided, however, that our general partner shall not cause us to engage, directly or indirectly in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. Affiliates of our general partner generally will not be obligated to present to us or our general partner any business opportunities unless and until the business opportunities have been rejected by other publicly traded affiliates of our general partner, including Enterprise GP Holdings and Enterprise Products Partners. For a further description of limits on our business, please read “Certain Relationships and Related Party Transactions — Administrative Services Agreement.”

Power of Attorney

Each limited partner, and each person who acquires a common unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants the authority to amend, and to make consents and waivers under, our partnership agreement. Please read “— Amendments to Our Partnership Agreement.”

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest. For a description of these cash distribution provisions, please read “Cash Distribution Policy and Restrictions on Distributions.”

Capital Contributions

Common unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue

134

additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:


	•	to remove or replace the general partner;

	•	to approve some amendments to the partnership agreement; or

	•	to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If in the future, by our ownership in an operating company or otherwise, it is determined that we conduct business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. In voting their common units, affiliates of our general partner will have no fiduciary duty or obligation whatsoever to us

135

or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.


Issuance of additional common units or other equity interests		No approval right.

Amendment of our partnership agreement		Certain amendments may be made by our general partner without the approval of our unitholders. Other amendments generally require the approval of holders of a majority of our outstanding common units. Please read “— Amendments to Our Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets		Holders of a majority of our outstanding common units in certain circumstances. Please read “— Merger, Sale or Other Disposition of Assets.”

Dissolution of our partnership		Holders of a majority of our outstanding common units. Please read “— Termination or Dissolution.”

Reconstitution of our partnership upon dissolution		Holders of a majority of our outstanding common units. Please read “— Termination or Dissolution.”

Withdrawal of our general partner		Under most circumstances, the approval of holders of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of the general partner prior to December 31, 2016 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of Our General Partner.”

Removal of our general partner		Holders of not less than 662/3% of the outstanding common units, including common units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of Our General Partner.”

Transfer of the general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to (i) an affiliate (other than an individual) or (ii) another entity in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of holders of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2016. Please read “— Transfer of General Partner Interest.”

Transfer of ownership interests in our general partner		No approval required at any time. Please read “— Transfer of Ownership Interests in Our General Partner.”

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities that may be senior to our common units on terms and conditions established by our general partner in its sole discretion without the approval of our unitholders.

136

It is possible that we will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our cash distributions. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, in the sole discretion of our general partner, may have special voting rights to which common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

Upon issuance of additional common units or other partnership securities, our general partner will be entitled, but will not be required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. If the general partner does not make additional capital contributions to maintain its 2% general partner interest in us, its interest will be decreased to its pro rata portion of its relative capital account. Please read “— Liquidation and Distribution of Proceeds.” Our general partner and its affiliates have the right, which they may from time to time assign in whole or in part to any of their affiliates, to purchase common units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain their limited partner percentage interests in us that existed immediately prior to the issuance. Our general partner and its affiliates will hold approximately 36.0% of our outstanding common units after this offering (or approximately 26.3% if the underwriters exercise their option to purchase additional common units in full). The holders of common units will not have preemptive rights to acquire additional common units or other partnership interests in us.

Amendments to Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of common units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by holders of a majority of our outstanding common units.

Prohibited Amendments

No amendment may be made that would:

(1) enlarge the obligations of any limited partner without its consent, unless approved by holders of at least a majority of the type or class of limited partner interests so affected; or

(2) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in clauses (1) or (2) above can be amended upon the approval of the holders of at least 90% of the outstanding common units.

137

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

(1) a change in the name of the partnership, the location of the partnership’s principal place of business, the partnership’s registered agent or its registered office;

(2) the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

(3) a change that our general partner determines to be necessary or appropriate for the partnership to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that none of us or our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

(4) an amendment that is necessary, in the opinion of our counsel, to prevent the partnership or our general partner or its directors, officers, agents or trustees, from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed;

(5) any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

(6) an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

(7) any amendment that our general partner determines to be necessary or appropriate for the formation by the partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

(8) a change in our fiscal year or taxable year and related changes;

(9) certain mergers or conveyances set forth in our partnership agreement; and

(10) any other amendments substantially similar to any of the matters described in (1) through (9) above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner or if our general partner determines that those amendments:

(1) do not adversely affect our limited partners in any material respect;

(2) are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

(3) are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, compliance with any of which our general partner deems to be in the partnership’s best interest and the best interest of our limited partners;

(4) are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

(5) are required to effect the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

138

Opinion of Counsel and Unitholder Approval

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in us or our subsidiaries being treated as an entity for federal income tax purposes in connection with any of the amendments described under “— Amendments to Our Partnership Agreement — No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding common units unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

Our partnership agreement generally prohibits our general partner, without the prior approval of holders of a majority of our outstanding common units, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner, without the approval of our unitholders, may merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other transaction or event.

Termination or Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

(1) the election of our general partner to dissolve us, if approved by a majority of the members of our general partner’s audit and conflicts committee and the holders of a majority of our outstanding common units;

(2) there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

(3) the entry of a decree of judicial dissolution of our partnership; or

(4) the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under clause (4) above, the holders of a majority of our outstanding common units may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing a successor general partner an entity approved by the

139

holders of a majority of our outstanding common units, excluding those common units held by our general partner and its affiliates, subject to receipt by us of an opinion of counsel to the effect that:


	•	the action would not result in the loss of limited liability of any limited partner; and

	•	we would not be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the person authorized to wind up our affairs (the liquidator) will, acting with all the powers of our general partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets. The proceeds of the liquidation will be applied as follows:


	•	first, towards the payment of all of our creditors and the creation of a reserve for contingent liabilities; and

	•	then, to all partners in accordance with the positive balance in their respective capital accounts.

Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause undue loss to our partners, our general partner may distribute assets in kind to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2016 without obtaining the approval of a majority of the members of our audit and conflicts committee and holders of a majority of our outstanding common units, excluding those held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2016, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our general partner may withdraw without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of our outstanding common units are held or controlled by one person and its affiliates other than our general partner and its affiliates.

Upon the voluntary withdrawal of our general partner, the holders of a majority of our outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of our outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, agree to continue our business and to appoint a successor general partner.

Our general partner may not be removed unless that removal is approved by (i) the audit and conflicts committee of our general partner and (ii) holders of not less than 662/3% of our outstanding common units, including common units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. In addition, if our general partner is removed as our general partner under circumstances where cause does not exist and common units held by our general partner and its affiliates are not voted in favor of such removal, our general partner will have the right to convert its general partner interest into common units or to receive cash in exchange for such interests. Any removal of this kind is also subject to the approval of a successor general partner by a majority of our outstanding common units, including those held by our general partner and its affiliates. The ownership of more than 331/3% of the outstanding common units by our general partner and its affiliates would give it the practical ability to prevent its removal. Upon completion of this offering, affiliates of our general partner will own approximately 36.0%

140

of the outstanding common units (or approximately 26.3% if the underwriters exercise their option to purchase additional common units in full).

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to its fair market value. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for a cash payment equal to its fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Interest

Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:


	•	an affiliate of the general partner (other than an individual); or

	•	another entity as part of the merger or consolidation of the general partner with or into another entity or the transfer by the general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any part of its general partner interest in us to another entity prior to December 31, 2016 without the approval of holders of a majority of the common units outstanding, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and it affiliates may at any time transfer common units to one or more persons without unitholder approval.

Transfer of Ownership Interests in Our General Partner

At any time, Enterprise Products OLP may sell or transfer all or part of its ownership interest in our general partner without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner as general partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of common units, that person or group loses voting rights on all of its common units. This loss of voting rights does not apply to any person or group that acquires the common units from our general partner or its affiliates and any transferees of that person or group approved by our general partner.

141

Limited Call Right

If at any time our general partner and its affiliates hold more than 80% of the outstanding limited partner interests of any class, our general partner will have the right, but not the obligation, which it may assign in whole or in part to any of its affiliates or us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:


	•	the highest cash price paid by either our general partner or any of its affiliates for any limited partners interests of the class purchased within the 90 days preceding the date our general partner first mails notice of its election to purchase the limited partner interests; and

	•	the current market price of the limited partner interests of the class as of the date three days prior to the date that notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Common Units.”

Upon completion of this offering, affiliates of our general partner will own approximately 7,298,551 of our common units, representing approximately 36.0% of our outstanding common units (or 5,348,551 common units representing approximately 26.3% of our outstanding common units if the underwriters exercise their option to purchase additional common units in full).

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of common units then outstanding, unitholders on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by non-citizen assignees will be voted by our general partner and our general partner will distribute the votes on those common units in the same ratios as the votes of limited partners on other common units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by our unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of common units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding common units. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding common units, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the common units, in which case the quorum will be the greater percentage.

Each record holder of a common unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities” above. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

142

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the transferred units when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the common units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his common units and may not receive distributions in kind upon our liquidation.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, subject to certain limitations expressly provided in our partnership agreement, from and against all losses, claims, damages or similar events:

(1) our general partner;

(2) any departing general partner;

(3) any person who is or was an affiliate of our general partner or any departing general partner;

(4) any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in (1), (2) or (3) above;

(5) any person who is or was serving as an officer, director, member, partner, fiduciary or trustee of another person at the request of the general partner or any departing general partner; and

(6) any person designated by our general partner.

This indemnification is required unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these indemnitees acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the indemnitee’s conduct was unlawful.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under the partnership agreement.

143

Resolution of Conflicts of Interest

As discussed elsewhere in this prospectus, our partnership agreement provides contractual procedures for the resolution of certain conflicts of interest that are binding on all partners and modifies certain fiduciary duties otherwise applicable under Delaware law.

Unless otherwise expressly provided in our partnership agreement, whenever a potential conflict of interest exists or arises between our general partner or any of its affiliates, on the one hand, and us, any of our subsidiaries or any partner, on the other hand, any resolution or course of action by the general partner or its affiliates in respect of such conflict of interest shall be permitted and deemed approved by all partners, and shall not constitute a breach of our partnership agreement or of any agreement contemplated thereby, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is or, by operation of the partnership agreement is deemed to be, fair and reasonable to us; provided that, any conflict of interest and any resolution of such conflict of interest shall be deemed fair and reasonable to us if such conflict of interest or resolution is (i) approved by “Special Approval” (i.e., by a majority of the members of the Audit and Conflicts Committee), or (ii) on terms no less favorable to us than those generally being provided to or available from unrelated third parties. The Audit and Conflicts Committee (in connection with Special Approval) shall be authorized in connection with its resolution of any conflict of interest to consider (i) the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest; (ii) the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us); (iii) any customary or accepted industry practices and any customary or historical dealings with a particular Person; (iv) any applicable generally accepted accounting or engineering practices or principles; and (v) such additional factors as the Audit and Conflicts Committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances. Nothing contained in the partnership agreement, however, is intended to nor shall it be construed to require the Audit and Conflicts Committee to consider the interests of any person other than the Partnership. In the absence of bad faith by the Audit and Conflicts Committee or our general partner, the resolution, action or terms so made, taken or provided (including granting Special Approval) by the Audit and Conflicts Committee or our general partner with respect to such matter shall be conclusive and binding on all persons (including all partners) and shall not constitute a breach of the partnership agreement, or any other agreement contemplated thereby, or a breach of any standard of care or duty imposed in the partnership agreement or under the Delaware Revised Uniform Limited Partnership Act or any other law, rule or regulation. It shall be presumed that the resolution, action or terms made, taken or provided by the Audit and Conflicts Committee or our general partner was not made, taken or provided in bad faith, and in any proceeding brought by any limited partner or by or on behalf of such limited partner or any other limited partner or us challenging such resolution, action or terms, the person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption.

Whenever our general partner makes a determination or takes or declines to take any other action, or any of its affiliates causes it to do so, in its capacity as our general partner as opposed to in its individual capacity, whether under our partnership agreement, or any other agreement contemplated thereby or otherwise, then unless another express standard is provided for in our partnership agreement, our general partner, or such affiliates causing it to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by our partnership agreement, any other agreement contemplated thereby or under the Delaware Revised Uniform Limited Partnership Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of our partnership agreement, the person or persons making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the partnership.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive

144

compensation and other amounts paid to persons who perform services for us or our general partner and expenses allocated to us or otherwise incurred by our general partner in connection with operating our business. The general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a common unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

A limited partner can, for a purpose reasonably related to the limited partner’s interest as a limited partner, upon reasonable demand stating the purpose of such demand and at his own expense, obtain:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	information as to the amount of cash and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

	•	copies of our partnership agreement, our certificate of limited partnership, amendments to either of them and powers of attorney which have been executed under our partnership agreement;

	•	information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets and other information the disclosure of which our general partner believes in good faith is not in our best interest or which we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all costs and expenses incidental to any such registration and offering on behalf of our general partner or its affiliates, excluding underwriting discounts and commissions. Please also read “Common Units Eligible for Future Sale.”

145

COMMON UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, our general partner or its affiliates, will hold an aggregate of 7,298,551 common units, representing approximately 36.0% of our outstanding common units (or 5,348,551 common units, representing approximately 26.3% of our outstanding common units if the underwriters’ option to purchase additional common units is exercised in full). The sale of these common units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1% of the total number of the securities outstanding; or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements, and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the current public information requirements, volume limitations, manner of sale provisions, and notice requirements of Rule 144.

The partnership agreement provides that we may issue an unlimited number of limited partner interests without a vote of the unitholders. Such common units may be issued on the terms and conditions established by our general partner. Any issuance of additional common units would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to, and market price of, common units then outstanding. Please read “Description of Material Provisions of Our Partnership Agreement — Issuance of Additional Securities.”

Under the partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units that they hold. Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units to require registration of any of these common units and to include any of these common units in a registration by us of other common units, including common units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their common units in private transactions at any time, subject to compliance with applicable laws.

We, the officers and directors of our general partner, and our principal unitholders have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

146

MATERIAL TAX CONSEQUENCES

This section is a discussion of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Andrews Kurth LLP, counsel to our general partner and us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Duncan Energy Partners L.P. and our operating partnership.

The following discussion does not address all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs), employee benefit plans or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of the common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Andrews Kurth LLP and are based on the accuracy of the representations made by us and our general partner.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Andrews Kurth LLP. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this discussion may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Andrews Kurth LLP has not rendered an opinion with respect to the following specific federal income tax issues: the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration,

147

development, mining or production, processing, refining, transportation, storage and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current income is not qualifying income; however, this estimate could change from time to time. Based on and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Andrews Kurth LLP is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Andrews Kurth LLP that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and our operating partnership will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Andrews Kurth LLP has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Andrews Kurth LLP has relied include:


	•	Neither we nor our operating partnership has elected nor will elect to be treated as a corporation; and

	•	For each taxable year, more than 90% of our gross income will be income that Andrews Kurth LLP has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Andrews Kurth LLP’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Duncan Energy Partners L.P. will be treated as partners of Duncan Energy Partners L.P. for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Duncan Energy Partners L.P. for federal income tax purposes.

148

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Items of our income, gain, loss and deduction would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Duncan Energy Partners L.P. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Duncan Energy Partners L.P. for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis in his common units generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including our general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of the non-pro rata portion of that distribution over the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions. We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2009, will be allocated on a cumulative basis an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. We anticipate that after the taxable year ending December 31, 2009, the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The

149

actual percentage of distributions that will constitute taxable income could be higher or lower than our estimation above, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater if:


	•	gross income from operations exceeds the amount required to make the minimum quarterly distribution on all units, yet we only distribute the minimum quarterly distribution on all units; or

	•	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of the offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that amount is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or a unitholder’s salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when the unitholder disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

150

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed to us by the general partner and its affiliates, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder purchasing common units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in such amount and manner as is needed to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with

151

the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to us;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

Andrews Kurth LLP is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Andrews Kurth LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. In general the highest effective United States federal income tax rate for individuals is currently 35% and the maximum United States federal income tax rate for net capital gains of an individual is currently 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election. We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

152

Where the remedial allocation method is adopted (which we will adopt), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with the Treasury Regulations. Please read “— Uniformity of Units.”

Although Andrews Kurth LLP is unable to opine as to the validity of this approach because there is no controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the Treasury Regulations under Section 743 of the Internal Revenue Code but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a basis reduction or a built-in loss is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his

153

taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner and its affiliates. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Because our general partner may determine not to adopt the remedial method of allocation with respect to any difference between the tax basis and the fair market value of goodwill immediately prior to this or any future offering, we may not be entitled to any amortization deductions with respect to any goodwill conveyed to us on formation or held by us at the time of any future offering. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a common unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some, or all, of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may be able to amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold

154

at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or

155

loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Andrews Kurth LLP is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements. A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder generally is required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirement.

Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year different from our taxable year, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6) and Treasury Regulation Section 1.197-2(g)(3). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets, and Treasury Regulations Section 1.197-2(g)(3). Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive

156

depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. Our counsel, Andrews Kurth LLP, is unable to opine on the validity of any of these positions. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold tax at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes each unitholder’s share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions,

157

some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will in all cases yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Andrews Kurth LLP can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(2) whether the beneficial owner is

(a) a person that is not a United States person,

(b) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

158

Accuracy-related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, “substantial authority,” or

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000. If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions. If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures” above.

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy-related Penalties,”

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and

	•	in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in Louisiana and Texas.

159

Each of these states, other than Texas, currently imposes a personal income tax on individuals. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend on, his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state and local, as well as United States federal tax returns, that may be required of him. Andrews Kurth LLP has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

160

SELLING UNITHOLDER

If the underwriters exercise all or any portion of their option to purchase additional common units, we will issue up to 1,950,000 additional common units, and we will redeem an equal number of common units from Enterprise Products OLP, who may be deemed to be a selling unitholder in this offering. The redemption price per common unit will be equal to the price per common unit (net of underwriting discounts and a structuring fee) sold to the underwriters upon exercise of their option.

The following table sets forth information concerning the ownership of common units by Enterprise Products OLP. The numbers in the table are presented assuming:


	•	the underwriters’ option to purchase additional units is not exercised; and

	•	the underwriters exercise their option to purchase additional units in full.

Assuming

Underwriters’

Option is

Exercised

Name of Selling Unitholder

Not Exercised

Percent(1)

in Full

Percent(1)

Enterprise Products Operating L.P.

common units

7,298,551

36.0

5,348,551

26.3


(1)		Percentage of total common units outstanding, but excluding 2% general partner interest.

161

UNDERWRITING

Lehman Brothers Inc. is acting as representative of the underwriters and as sole book-running manager of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to this registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:


	Number of
Underwriters	Common Units

Lehman Brothers Inc.





Total		13,000,000

The underwriting agreement provides that the underwriters’ obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:


	•	the obligation to purchase all of the common units offered hereby if any of the common units are purchased;

	•	the representations and warranties made by us to the underwriters are true;

	•	there has been no material change in our financial condition or in the financial markets; and

	•	we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.


	No Exercise	Full Exercise

Per Unit	$	$
Total	$	$

Lehman Brothers Inc. has advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per unit. After the offering, Lehman Brothers Inc. may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be $ (exclusive of underwriting discounts and commissions). The underwriters have agreed to reimburse us for up to $ of our expenses incurred in connection with the offering of 13,000,000 common units. In no event will the maximum amount of compensation to be paid to NASD members in connection with this offering exceed 10% plus 0.5% for bona fide due diligence.

We will pay a structuring fee equal to $ to Lehman Brothers Inc. in consideration of advice rendered related to the structure of this offering and the related transactions.

Option to Purchase Additional Common Units

We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement to purchase, from time to time, in whole or in part, up to an aggregate of 1,950,000 common units

162

at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than 13,000,000 common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s percentage underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

Indemnification

We, our general partner and Enterprise Products Partners have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933 and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.

Directed Unit Program

At our request, Lehman Brothers Inc. has established a Directed Unit Program under which they have reserved up to 650,000 common units offered hereby at the public offering price for officers, directors, employees and certain other persons associated with us. The number of common units available for sale to the general public will be reduced to the extent such persons purchase common units reserved under the Directed Unit Program. The common units reserved for sale under the Directed Unit Program will be subject to a 180-day lock-up agreement. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered hereby.

Lock-Up Agreements

We, certain of our affiliates and all of the directors and executive officers of our general partner have agreed that, without the prior written consent of Lehman Brothers Inc., we and they will not directly or indirectly, offer, pledge, announce the intention to sell, sell, contract to sell, sell an option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, or otherwise transfer or dispose of any common units or any securities which may be converted into or exchanged for any common units, enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the common units, make any demand for or exercise any right or file or cause to be filed a registration statement with respect to the registration of any common units or securities convertible or exchangeable into common units or any of our other securities or publicly disclose the intention to do any of the foregoing for a period of 180 days from the date of this prospectus other than permitted transfers.

The 180-day restricted period described in the preceding paragraph will be extended if:


	•	during the last 17 days of the 180-day restricted periods we issue an earnings release or announce material news or a material event; or

	•	prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.

The restrictions described in this paragraph do not apply to:


	•	the issuance and sale of common units by us to the underwriters pursuant to the underwriting agreement; or

	•	the issuance and sale of common units, phantom units, restricted units and options under our existing employee benefits plans, including sales pursuant to “cashless-broker” exercises of options to purchase common units in accordance with such plans as consideration for the exercise price and withholding taxes applicable to such exercises.

163

Lehman Brothers Inc., in its sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common units and other securities from lock-up agreements, Lehman Brothers Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price was negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives considered:


	•	the history and prospects for the industry in which we compete;

	•	our financial information;

	•	the ability of our management and our business potential and earnings prospects;

	•	the prevailing securities markets at the time of this offering, and

	•	the recent market prices of, and the demand for, publicly traded common units of generally comparable entities.

Stabilization, Short Positions and Penalty Bids

The underwriters may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Securities Exchange Act of 1934:


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

	•	A short position involves a sale by the underwriters of common units in excess of the number of units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of units they are obligated to purchase is not greater than the number of units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of units involved is greater than the number of units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

	•	Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

	•	Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might

164

otherwise exist in the open market. These transactions may be effected on The New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

We intend to apply to list our common units on the New York Stock Exchange under the symbol “DEP.”

In connection with the listing of our common units on the New York Stock Exchange, the underwriters have advised us that they will undertake to sell round lots of 100 units or more to a minimum of 400 beneficial owners.

Discretionary Sales

The underwriters have advised us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

NASD Conduct Rule 2810

Because the National Association of Securities Dealers, Inc., or NASD, views the common units offered by this prospectus as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the Conduct Rules of the NASD.

165

Relationships

Certain of the underwriters may in the future perform investment banking and advisory services for us from time to time for which they may in the future receive customary fees and expenses. The underwriters may, from time to time, engage in transactions with or perform services for us in the ordinary court of their business.

Affiliates of are lenders under our new credit facility.

In addition, certain of the underwriters and their affiliates have performed, and may in the future perform, investment banking, commercial banking and advisory services for Enterprise Products Partners, EPCO, Inc. and their affiliates for which they have received or will receive customary fees and expenses.

166

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The combined financial statements of Duncan Energy Partners Predecessor as of December 31, 2005 and 2004 and for each of the three years in the period ended December 31, 2005 and the related financial statement schedule included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report included in this prospectus (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the preparation of the combined financial statements of Duncan Energy Partners Predecessor from the separate records maintained by Enterprise Products Partners L.P.) and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheet of Duncan Energy Partners L.P. as of September 30, 2006 and the balance sheet of DEP Holdings, LLC as of October 31, 2006 included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports which are included in this prospectus, and are included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Commission a registration statement on Form S-1 regarding the common units offered by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you should review the full registration statement, including its exhibits and schedules, filed under the Securities Act of 1933, as amended. The registration statement of which this prospectus constitutes a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the Commission at Judiciary Plaza, 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the Commission at prescribed rates by writing to the public reference room maintained by the Commission at Judiciary Plaza, 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the Commission at 1-800-SEC-0330. The Commission maintains a website on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded at no cost from the Commission’s web site. We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

167

FORWARD-LOOKING STATEMENTS

This prospectus contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. In particular, a significant amount of information included under “Cash Distribution Policy and Restrictions on Distributions” is comprised of forward-looking statements. When used in this prospectus or the documents we have incorporated herein or therein by reference, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “should,” “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 reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurances 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 review the risk factors described under “Risk Factors” in this prospectus.

168

INDEX TO FINANCIAL STATEMENTS


Duncan Energy Partners L.P.
Unaudited Pro Forma Condensed Combined Financial Statements:
Introduction			F-2
Unaudited Pro Forma Condensed Statement of Combined Operations for the Six Months Ended June 30, 2006			F-3
Unaudited Pro Forma Condensed Statement of Combined Operations for the Year Ended December 31, 2005			F-4
Unaudited Pro Forma Condensed Combined Balance Sheet at June 30, 2006			F-5
Notes to Unaudited Pro Forma Condensed Combined Financial Statements			F-6
Duncan Energy Partners Predecessor
Audited Combined Financial Statements:
Report of Independent Registered Public Accounting Firm			F-12
Combined Balance Sheets at December 31, 2005 and 2004			F-13
Statements of Combined Operations and Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003			F-14
Statements of Combined Cash Flows for the Years Ended December 31, 2005, 2004 and 2003			F-15
Statements of Combined Owners’ Net Investment for the Years Ended December 31, 2005, 2004 and 2003			F-16
Notes to Combined Financial Statements and Supplemental Schedule			F-17
Duncan Energy Partners Predecessor
Unaudited Condensed Combined Financial Statements:
Unaudited Condensed Combined Balance Sheets at June 30, 2006 and December 31, 2005			F-42
Unaudited Condensed Statements of Combined Operations and Comprehensive Income for the Three and Six Months Ended June 30, 2006 and 2005			F-43
Unaudited Condensed Statements of Combined Cash Flows for the Six Months Ended June 30, 2006 and 2005			F-44
Unaudited Condensed Statements of Combined Owners’ Net Investment for the Six Months Ended June 30, 2006			F-45
Notes to Unaudited Condensed Combined Financial Statements			F-46
Duncan Energy Partners L.P.
Audited Balance Sheet:
Report of Independent Registered Public Accounting Firm			F-60
Balance Sheet at September 30, 2006			F-61
Note to Balance Sheet			F-62
DEP Holdings, LLC
Audited Balance Sheet:
Report of Independent Registered Public Accounting Firm			F-63
Balance Sheet at October 31, 2006			F-64
Note to Balance Sheet			F-65

F-1

DUNCAN ENERGY PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Introduction

The unaudited pro forma condensed combined financial statements are based upon the historical combined balance sheet and results of combined operations of Duncan Energy Partners Predecessor set forth elsewhere in this prospectus. Duncan Energy Partners L.P. (the “Partnership”) will own and operate the business of the Duncan Energy Partners Predecessor effective with the closing of this initial public offering. Since the transactions are considered to be a reorganization of entities under common control, we will record these investments at the historical cost basis of each, as recognized by Enterprise Products Partners at the date of purchase. Unless the context otherwise requires, references in the following pro forma financial statements include the Partnership and its operating company. The unaudited pro forma condensed combined financial statements for the Partnership have been derived from the historical combined financial statements of the Duncan Energy Partners Predecessor set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical combined financial statements and the related notes contained therein. The pro forma condensed combined financial statements have been prepared on the basis that the Partnership will be treated as a partnership for federal income tax purposes. The unaudited pro forma condensed combined financial statements should be read in conjunction with the notes accompanying these pro forma condensed combined financial statements and with the historical combined financial statements and related notes of Duncan Energy Partners Predecessor set forth elsewhere in this prospectus.

The unaudited pro forma condensed combined balance sheet and the pro forma condensed statement of combined operations were derived by adjusting the historical combined financial statements of the Duncan Energy Partners Predecessor. The adjustments were based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed combined financial statements.

The unaudited pro forma condensed combined financial statements are not necessarily indicative of the results that actually would have occurred if the Partnership had assumed the operations of the Duncan Energy Partners Predecessor on the dates indicated or which would be obtained in the future.

F-2

DUNCAN ENERGY PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED STATEMENT OF COMBINED OPERATIONS

For the Six Months Ended June 30, 2006


	Duncan
	Energy Partners									Adjustments			As Adjusted
	Predecessor			Pro Forma			Partnership			Related to This			Partnership
	Historical			Adjustments			Pro Forma			Offering			Pro Forma
	(Dollars in thousands, except per unit amounts)

REVENUES	$	503,791		$	(10,785	)(b)	$	499,210					$	499,210
					6,204	(c)
COST AND EXPENSES
Operating costs and expenses		478,586			(277	)(d)		478,309						478,309
General and administrative costs		1,735			1,250	(e)		2,985						2,985

Total costs and expenses		480,321			973			481,294						481,294

EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES		354						354						354

OPERATING INCOME		23,824			(5,554	)		18,270						18,270

OTHER INCOME (EXPENSE)
Interest expense										$	(6,647	)(f)		(6,647	)
Other, net		4						4						4

Other income (expense)		4						4			(6,647	)		(6,643	)

INCOME BEFORE PARENT’S SHARE AND PROVISION FOR INCOME TAXES		23,828			(5,554	)		18,274			(6,647	)		11,627
PROVISION FOR INCOME TAXES		(21	)					(21	)					(21	)

INCOME BEFORE PARENT’S SHARE		23,807			(5,554	)		18,253			(6,647	)		11,606
PARENT’S SHARE OF INTEREST											(7,895	)(g)		(7,895	)

INCOME FROM CONTINUING OPERATIONS	$	23,807		$	(5,554	)	$	18,253		$	(14,542	)	$	3,711

BASIC AND DILUTED EARNINGS PER COMMON UNIT — as allocated to public limited partners other than the Parent
Income allocated to public units													$	3,711

Number of public units used in denominator											13,000	(h)		13,000

Basic and diluted earnings per unit — public													$	0.29

See Notes to Unaudited Pro Forma Condensed Combined Financial Statements

F-3

DUNCAN ENERGY PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED STATEMENT OF COMBINED OPERATIONS

For the Year Ended December 31, 2005


	Duncan
	Energy Partners									Adjustments			As Adjusted
	Predecessor			Pro Forma			Partnership			Related to This			Partnership
	Historical			Adjustments			Pro Forma			Offering			Pro Forma

REVENUES	$	953,397		$	(18,439	)(b)	$	946,568					$	946,568
					11,610	(c)
COST AND EXPENSES
Operating costs and expenses		909,044			(3,055	)(d)		905,989						905,989
General and administrative costs		4,483			2,500	(e)		6,983						6,983

Total costs and expenses		913,527			(555	)		912,972						912,972

EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES		331						331						331

OPERATING INCOME		40,201			(6,274	)		33,927						33,927

OTHER EXPENSE
Interest expense		(532	)					(532	)	$	(13,400	)(f)		(13,932	)

Other expense		(532	)					(532	)		(13,400	)		(13,932	)

INCOME BEFORE PARENT’S SHARE		39,669			(6,274	)		33,395			(13,400	)		19,995
PARENT’S SHARE OF INCOME											(14,226	)(g)		(14,226	)

INCOME FROM CONTINUING OPERATIONS	$	39,669		$	(6,274	)	$	33,395		$	(27,626	)	$	5,769

BASIC AND DILUTED EARNINGS PER COMMON UNIT — as allocated to public limited partners other than the Parent
Income allocated to public units													$	5,769

Number of public units used in denominator											13,000	(h)		13,000

Basic and diluted earnings per unit — public													$	0.44

See Notes to Unaudited Pro Forma Condensed Combined Financial Statements

F-4

DUNCAN ENERGY PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET

June 30, 2006


	Duncan
	Energy Partners							Adjustments			As Adjusted
	Predecessor		Pro Forma			Partnership		Related to This			Partnership
	Historical		Adjustments			Pro Forma		Offering			Pro Forma

ASSETS
Current assets
Cash								$	198,000	(f)	$	20,394	(a)
									241,420	(h)
									(419,026	)(i)
Accounts receivable, net	$	63,166				$	63,166					63,166
Inventories		13,636					13,636					13,636
Other current assets		120					120					120

Total current assets		76,922					76,922		20,394			97,316
Property, plant and equipment, net		539,929	$	135,368	(a)		675,297					675,297
Investments in and advances to unconsolidated affiliate		2,788					2,788					2,788
Intangible assets		7,082					7,082					7,082
Other assets									2,000	(f)		2,000

Total assets	$	626,721	$	135,368		$	762,089	$	22,394		$	784,483


LIABILITIES AND EQUITY
Current liabilities
Accounts payable and accrued expenses	$	60,443				$	60,443				$	60,443
Other current liabilities		7,686	$	(804	)(d)		6,882					6,882

Total current liabilities		68,129		(804	)		67,325					67,325
Long-term debt								$	200,000	(f)		200,000
Other long-term liabilities		658					658					658
Parent’s interest in the Partnership									694,106	(g)		275,080
									(419,026	)(i)
Equity
Owners’ net investment		557,934		135,368	(a)		694,106		(694,106	)(g)		—
				804	(d)
Partners’ equity — public									241,420	(h)		241,420

Total equity/owner’s net investment		557,934		136,172			694,106		(452,686	)		241,420

Total liabilities/owners’ net investment and equity	$	626,721	$	135,368		$	762,089	$	22,394		$	784,483

See Notes to Unaudited Pro Forma Condensed Combined Financial Statements

F-5

DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED FINANCIAL STATEMENTS

1. Basis of Presentation, the Offering and Other Transactions.

The historical financial information is derived from the historical combined financial statements of Duncan Energy Partners Predecessor. The unaudited pro forma condensed combined statements of combined operations for the six months ended June 30, 2006 and for the year ended December 31, 2005 assume the pro forma transactions noted herein occurred at the beginning of each year presented. The unaudited pro forma condensed combined balance sheet presents the financial effects of the pro forma transactions noted herein as if they had occurred on June 30, 2006.

The pro forma financial statements reflect the following significant transactions:


	•	The August 2006 purchase of a pipeline asset by Enterprise Products Partners for approximately $97.7 million in cash, the subsequent contribution of this pipeline to South Texas NGL, and estimated additional costs of $37.7 million (including $8 million to acquire a pipeline asset from TEPPCO Partners) required to modify this pipeline and to acquire and construct additional pipelines in order to place this system into operation in January 2007. The pro forma financial statements do not reflect estimated additional capital expenditures of $30.9 million that will be made by South Texas NGL to complete planned expansions to this system subsequent to the closing of this offering. We will retain cash in an amount equal to our share of the additional capital expenditures (approximately $20.4 million) from the net proceeds of this offering in order to fund our share of the planned expansion costs. The pro forma combined results of operations does not reflect any results attributable to the historical activities of this pipeline.

	•	The contribution of a 66% interest in each of the following entities, all of which are wholly-owned subsidiaries of Enterprise Products Partners, and the retention by Enterprise Products Partners of a 34% interest in these entities:


	•	Mont Belvieu Caverns, L.P. (which will be converted into a limited liability company in January 2007 prior to its contribution to the Partnership)(“Mont Belvieu Caverns”), which receives, stores and delivers NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast;

	•	Acadian Gas, LLC (“Acadian Gas”), which gathers, transports, stores and markets natural gas in Louisiana utilizing over 1,000 miles of high-pressure transmission lines and lateral and gathering lines and a leased storage cavern;

	•	Sabine Propylene Pipeline L.P. (“Sabine Propylene”), which transports polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect located in Cameron Parish, Louisiana;

	•	Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), which transports chemical-grade propylene between Sorrento, Louisiana and Mont Belvieu, Texas; and

	•	South Texas NGL Pipelines, LLC (“South Texas NGL”), which will transport NGLs from Corpus Christi, Texas to Mont Belvieu, Texas. The pipeline system currently owned, together with pipelines being acquired and being constructed by South Texas NGL, is undergoing modifications to enable it to transport NGL products for Enterprise Products Partners beginning in January 2007. Estimated additional capital expenditures of $30.9 million will be spent in 2007 to complete planned expansions to this system.


	•	The revision of related party storage contracts between the Partnership and Enterprise Products Partners to (i) increase certain storage fees paid by Enterprise Products Partners and (ii) reflect the allocation to Enterprise Products Partners of all storage measurement gains and losses relating to products under these agreements, and the execution of a limited liability company agreement for Mont Belvieu

F-6

DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED FINANCIAL STATEMENTS — (Continued)

Caverns providing for special allocations to Enterprise Products Partners and other agreements relating to other measurement gains and losses.


	•	The assignment to us of certain third party agreements that effectively reduce tariff rates previously charged by Lou-Tex Propylene and Sabine Propylene to Enterprise Products Partners for the transport of propylene volumes.

	•	The borrowing of $200 million under a new bank credit facility by us.

	•	The issuance and sale of 13,000,000 common units by us in this offering.

	•	The payment of estimated underwriting discounts and commissions, a structuring fee and other offering expenses.

	•	The use of net proceeds from the borrowing and this offering as consideration for the contributed ownership interests in Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL from Enterprise Products Partners.


2.	Pro Forma Adjustments and Assumptions

The pro forma adjustments made to the historical combined financial statements of Duncan Energy Partners Predecessor are as follows:

(a) Reflects the estimated costs to acquire and construct an NGL pipeline system that will transport mixed NGLs for Enterprise Products Partners from Corpus Christi, Texas to Mont Belvieu, Texas. In August 2006, Enterprise Products Partners purchased 223 miles of NGL pipelines extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The total purchase price for this asset was approximately $97.7 million in cash. This pipeline system will be owned by South Texas NGL (along with others being constructed and to be acquired) and will be used to transport mixed NGLs from Enterprise Products Partners’ facilities in South Texas to Mont Belvieu, Texas. The total estimated cost to acquire and construct the additional pipelines that will complete this system is $68.6 million. We expect that South Texas NGL will make capital expenditures of $37.7 million, including approximately $8 million to purchase a 10-mile pipeline from an affiliate, TEPPCO Partners L.P., to make this pipeline system operational prior to the closing of this offering. We expect that it will cost an additional $30.9 million to complete planned expansions of the South Texas NGL pipeline after the closing of this offering, of which our 66% share will be approximately $20.4 million. This additional cost is not reflected in the pro forma combined balance sheet as property, plant and equipment, because we expect to use cash on hand from the proceeds of this offering to fund these costs.

The Company’s historical financial information does not reflect any transactions related to the NGL pipeline asset acquired in August 2006. Furthermore, the pro forma adjustments are limited to those required to present an estimate of owners’ net investment immediately prior to the Partnership’s initial public offering. The pro forma combined results of operations do not reflect any results of operations attributable to the historical activities of the pipelines.

With respect to the pipeline acquired in August 2006, the seller has informed us that no discrete and separable financial information existed for this pipeline, which was comprised of two separately operated pipelines prior to our purchase. The seller had previously utilized these pipelines in different service than our anticipated use of the pipelines. With respect to the 10-mile pipeline to be purchased from TEPPCO Partners, L.P., this pipeline asset was part of their mainline service and operated by different management. No financial statement information is available for this minor component asset. There is no meaningful financial data available regarding the prior use of these pipelines by the sellers that would be meaningful to our investors. In addition, such data, if available, would not assist investors in

F-7

DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED FINANCIAL STATEMENTS — (Continued)

understanding either the evolution of the business (which is a new NGL transportation network) nor the track record of management (which will be different).

Collectively, the adjustments results in a pro forma increase of $135.4 million in property, plant and equipment and a corresponding increase in owners’ net investment for amounts estimated to be spent prior to the closing of this offering.

(b) Reflects a reduction in related party transportation rates we charge Enterprise Products Partners for usage of the Lou-Tex Propylene and Sabine Propylene pipelines. Enterprise Products Partners was the shipper of record on these two pipelines. Historically, Enterprise Products Partners was charged the maximum tariff rate for using these assets, which involved contracting with third parties to ship volumes on these pipelines under exchange agreements. Apart from such exchange agreements, Enterprise Products Partners did not utilize the Sabine Propylene and Lou-Tex Propylene assets. Concurrently with the closing of this offering, Enterprise Products Partners will assign certain agreements with third parties involving the use of our Sabine Propylene and Lou-Tex Propylene pipelines to us but will remain jointly and severally liable on those agreements.

In general, the revenues Enterprise Products Partners recognized in connection with such third party exchange agreements were less than the maximum tariff rate it paid us. In connection with our initial public offering, the transportation rates we charge Enterprise Products Partners for using the Lou-Tex Propylene and Sabine Propylene pipeline will be reduced to equal the amounts Enterprise Products Partners collects from third parties under its exchange agreements.

The pro forma reduction in revenues was $10.8 million for the six months ended June 30, 2006 and $18.4 million for the year ended December 31, 2005.

(c) Reflects an increase in related party storage fees charged to Enterprise Products Partners attributable to the use by its NGL fractionation, isomerization, and other businesses of the storage facilities owned by Mont Belvieu Caverns. Historically, such intercompany charges were below market and eliminated in the consolidated revenues and costs and expenses of Enterprise Products Partners. Prospectively, such rates will be market related.

The pro forma increase in revenues is $6.2 million for the six months ended June 30, 2006 and $11.6 million for the year ended December 31, 2005.

(d) Reflects the allocation to Enterprise Products Partners of measurement well gains and losses relating to products under storage agreements between Enterprise Products Partners and Mont Belvieu Caverns and the execution of a limited liability company agreement with Mont Belvieu Caverns providing for special allocations to Enterprise Products Partners and other agreements relating to other measurement gains and losses.

The pro forma decrease in operating costs and expenses reflecting the removal of such historical net measurement related losses is $0.3 million for the six months ended June 30, 2006 and $3.1 million for the year ended December 31, 2005. The pro forma balance sheet at June 30, 2006 reflects the removal of the related measurement reserve account, the balance of which was $0.8 million at June 30, 2006.

(e) Reflects the estimated general and administrative costs of the Partnership, exclusive of such costs of its subsidiaries. These estimated costs include accounting, legal and similar public company costs to be incurred by the Partnership in connection with the management and administration of its business activities. These costs include estimated related party amounts payable to EPCO, Inc. in connection with the administrative services agreement. For additional information regarding the administrative services agreement, please read “Certain Relationships and Related Party Transactions — Administrative Services Agreement.”

F-8

DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED FINANCIAL STATEMENTS — (Continued)

The pro forma increase in general and administrative costs is $1.3 million for the six months ended June 30, 2005 and $2.5 million for the year ended December 31, 2005.

(f) Reflects the borrowing of $200 million under a variable rate bank credit facility by the Partnership. For pro forma presentation purposes, we have assumed (i) a variable interest rate of 6.50% charged by this facility, (ii) $2 million of debt issuance costs and (iii) maturity date in five years.

Pro forma cash interest expense is $6.4 million for the six months ended June 30, 2006 and $13.2 million for the year ended December 31, 2005. If the variable interest rate we assumed in these calculations was 1/8% higher, pro forma cash interest expense would have been $6.6 million for the six months ended June 30, 2006 and $13.3 million for the year ended December 31, 2005. Pro forma interest expense includes non-cash amortization of debt issuance costs of $0.2 million for the six months ended June 30, 2006 and $0.4 million for the year ended December 31, 2005.

(g) Reflects the retention by Enterprise Products Partners (the sponsor of the Partnership) of an ownership interest in the Partnership’s consolidated subsidiaries, which will be Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL. The parent will own a 34% interest in each of the Partnership’s subsidiaries and will be allocated a portion of the earnings and cash flows of each subsidiary in accordance with this ownership percentage. However, the parent’s 34% earnings allocation with respect to Mont Belvieu Caverns is after any special allocations to the parent related to the subsidiary’s net measurement gain or loss each period.

In addition, the pro forma adjustments reflect the sponsor’s ownership of the Partnership’s 2% general partner and approximately 36% of its outstanding common units (assuming no exercise of the underwriter’s overallotment option with respect to this proposed offering). For financial reporting purposes, the ownership interests of Enterprise Products Partners are deemed to represent the parent (or sponsor) interest in the pro forma results of operations and financial position of the Partnership.

The following table presents the calculation of parent interest in the pro forma net assets of the Partnership and its subsidiaries at June 30, 2006 after giving effect to this proposed offering (before any exercise of the underwriters’ option to purchase additional common units):


Historical net assets of Duncan Energy Partners Predecessor	$	557,934
Pro forma adjustments to balance sheet accounts:
South Texas NGL (see Note (a))		135,368
Mont Belvieu Caverns (see Note (d))		804

Pro forma net assets before proposed initial public offering		694,106
Less Partnership payment to parent for ownership interests (see Note (i))		(419,026	)

Parent’s interest retained in net assets (approximately $236 million) and general partner interest and common units of Duncan Energy Partners	$	275,080

The pro forma balance sheet adjustment reclassifies the $694.1 million of net assets of the Partnership prior to its proposed initial public offering to parent interest.

F-9

DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED FINANCIAL STATEMENTS — (Continued)

The following table presents the calculation of parent’s share in the pro forma income of the Partnership and its subsidiaries for the periods indicated after giving effect to this proposed offering (before any exercise of the underwriters’ option to purchase additional common units):


	Units		Percent

Units to be sold by the Partnership in its proposed initial public offering (see Note (h))		13,000.0		62.8	%
Units issued by the Partnership to parent in connection with the Partnership’s acquisition of ownership interests (see Note (i))		7,298.6		35.2	%
General partner interest owned by parent		n/a		2.0	%

Totals		20,298.6		100.0	%


	Six Months			Year
	Ended			Ended
	June 30,			December 31,
	2006			2005

Historical combined income before cumulative effect of change in accounting principle of Duncan Energy Partners Predecessor	$	23,807		$	39,669
Pro forma adjustments to income statement amounts
Propylene transportation revenue adjustments (see Note (b))		(10,785	)		(18,439	)
Storage fee revenue adjustment (see Note (c))		6,204			11,610
Measurement loss allocated to parent as customer (see Note (d))		277			3,055
Special earnings allocation by Mont Belvieu Caverns of storage net measurement loss to parent		1,421			2,122

Pro forma income of subsidiaries subject to parent 34% interest		20,924			38,017
Less parent 34% interest in income of Partnership subsidiaries		(7,114	)		(12,926	)
Less incremental public company general and administrative costs (see Note (e))		(1,250	)		(2,500	)
Less interest expense (see Note (f))		(6,647	)		(13,400	)

Pro forma income to be allocated to DEP unitholders and GP		5,913			9,191
Less parent 2% general partner interest		(118	)		(183	)
Less parent interest attributed to its ownership of 36% of the limited partner units		(2,084	)		(3,239	)

Remaining pro forma income allocated to non-parent ownership interests — public	$	3,711		$	5,769

Summary of parent’s share of income and special allocation:
Parent 34% interest in income of subsidiaries	$	7,114		$	12,926
Special earnings allocation by Mont Belvieu Caverns of storage net measurement loss to parent		(1,421	)		(2,122	)
Parent 2% general partner interest in Partnership		118			183
Parent interest attributable to its ownership of 36% of the Partnership’s units		2,084			3,239

Total parent interest of Enterprise Products Partners	$	7,895		$	14,226

F-10

DUNCAN ENERGY PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

COMBINED FINANCIAL STATEMENTS — (Continued)

The pro forma income statement reflects an increase in Partnership interest expense of $7.9 million for the six months ended June 30, 2006 and $14.2 million for the year ended December 31, 2005.

(h) Reflects the proposed sale of 13,000,000 common units by the Partnership in this initial public offering at an assumed offering price of $20.00 per unit. Total net proceeds received from the sale of these units is approximately $241.4 million after deducting applicable underwriting discounts, commissions, structuring fees and other offering expenses of $18.6 million.

Pro forma basic and diluted income per unit is determined by dividing as adjusted income from continuing operations (which excludes the parent’s interest) by the number of common units sold in this offering. This pro forma adjustment does not include the receipt of any proceeds from the exercise of the underwriters’ overallotment option.

Staff Accounting Bulletin 1:B:3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, the Partnership intends to distribute approximately $419 million in cash to Enterprise Products Partners and affiliates. This distribution will be paid with (i) $198 million of net proceeds from borrowings under the new revolving credit facility and (ii) $221 million of the net proceeds from the issuance and sale of common units in this proposed offering. Assuming additional common units were issued to give effect to this distribution, pro forma net income per limited partners’ unit would have been $0.63 and $0.34 for the year ended December 31, 2005 and the six months ended June 30, 2006, respectively.

(i) Reflects the use of $419 million of cash, including proceeds from the proposed initial public offering described in Note (h) and the borrowing in Note (f), by the Partnership to purchase ownership interests in Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL from Enterprise Products Partners (the parent and sponsor). In addition to the cash consideration paid Enterprise Products Partners, the Partnership will issue Enterprise Products Partners 7,298,551 limited partner units representing approximately 36% of the outstanding common units before the exercise of the underwriters’ overallotment option.

We will retain approximately $20.4 million of the estimated net proceeds from this offering to fund our 66% share of the estimated 2007 capital expenditures for planned expansions to the South Texas NGL pipeline system. This assumes that $37.7 million of capital expenditures for our additional acquisition and construction related to this system have been paid prior to the closing date of this offering. See Note (a).

* * * *

F-11

DUNCAN ENERGY PARTNERS PREDECESSOR

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Enterprise Products GP, LLC, general partner of Enterprise Products Partners L.P.:

We have audited the accompanying combined balance sheets of Duncan Energy Partners Predecessor (the “Company”) as of December 31, 2005 and 2004, and the related statements of combined operations and comprehensive income, combined changes in net owners’ investment, and combined cash flows for each of the three years in the period ended December 31, 2005. Our audits also included the financial statement schedule listed in the Index at page F-1. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the combined financial position of Duncan Energy Partners Predecessor at December 31, 2005 and 2004, and the combined results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic combined financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

The accompanying combined financial statements have been prepared from the separate records maintained by Enterprise Products Partners L.P. and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from, and are applicable to Enterprise Products Partners L.P. or affiliates including EPCO, Inc.

/s/ Deloitte & Touche LLP

Houston, Texas

November 1, 2006

F-12

DUNCAN ENERGY PARTNERS PREDECESSOR

COMBINED BALANCE SHEETS


	December 31,
	2005		2004
	(Dollars in thousands)

ASSETS
Current assets
Accounts receivable — trade, net of allowance for doubtful accounts of $3,372 and $3,457 at December 31, 2005 and 2004, respectively	$	110,680	$	68,070
Inventories		9,855		4,815
Prepaid and other current assets		535		1,055

Total current assets		121,070		73,940
Property, plant and equipment, net		512,197		507,114
Investments in and advances to unconsolidated affiliate		2,375		2,003
Intangible assets, net of accumulated amortization of $929 and $697 at December 31, 2005 and 2004, respectively		7,198		7,430

Total assets	$	642,840	$	590,487


LIABILITIES AND OWNERS’ NET INVESTMENT
Current liabilities
Accounts payable — trade	$	1,171	$	121
Accrued gas payables		101,475		63,487
Accrued costs and expenses		967		1,408
Deposits from customers		357		4,640
Other current liabilities		10,495		11,112

Total current liabilities		114,465		80,768
Other long-term liabilities		608
Commitments and contingencies
Owners’ net investment		527,767		509,719

Total liabilities and owners’ net investment	$	642,840	$	590,487

See Notes to Combined Financial Statements

F-13

DUNCAN ENERGY PARTNERS PREDECESSOR

STATEMENTS OF COMBINED OPERATIONS

AND COMPREHENSIVE INCOME


	For Year Ended December 31,
	2005			2004			2003
	(Dollars in thousands)

REVENUES (See Note 7 — Business Segments)
Related parties	$	418,829		$	321,011		$	287,618
Third parties		534,568			427,920			380,616

Total revenues		953,397			748,931			668,234

COST AND EXPENSES (See Note 7 — Business Segments)
Operating costs and expenses
Related parties		60,978			29,410			25,318
Third parties		848,066			656,134			584,456

Total operating costs and expenses		909,044			685,544			609,774

General and administrative costs
Related parties		3,937			4,228			4,901
Third parties		546			1,214			1,237

Total general and administrative costs		4,483			5,442			6,138

Total costs and expenses		913,527			690,986			615,912

EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATE		331			231			131

OPERATING INCOME		40,201			58,176			52,453

OTHER INCOME (EXPENSE), NET		(532	)		(52	)		1

INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE		39,669			58,124			52,454
Cumulative effect of change in accounting principle		(582	)

NET INCOME and COMPREHENSIVE INCOME	$	39,087		$	58,124		$	52,454

See Notes to Combined Financial Statements

F-14

DUNCAN ENERGY PARTNERS PREDECESSOR

STATEMENTS OF COMBINED CASH FLOWS


	For Year Ended December 31,
	2005			2004			2003
	(Dollars in thousands)

OPERATING ACTIVITIES
Net income	$	39,087		$	58,124		$	52,454
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion in operating costs and expenses		19,453			18,374			17,882
Equity in income of unconsolidated affiliate		(331	)		(231	)		(131	)
Cumulative effect of change in accounting principle		582
Loss (gain) on sale of assets		5			(7	)
Changes in fair market value of financial instruments		52			5			2
Effect of changes in operating accounts:
Accounts receivable		(42,610	)		(17,612	)		(4,277	)
Inventories		(5,039	)		(1,297	)		(1,130	)
Prepaid and other current assets		312			1,203			802
Other assets								50
Accounts payable		1,049			(20	)		(2,279	)
Accrued gas payable		37,987			22,180			(1,819	)
Accrued expenses		(5,230	)		(1,077	)		(1,321	)
Deposits from customers		(4,283	)		(1,193	)		5,106
Other current liabilities		(459	)		1,014			(607	)
Other long-term liabilities		(7	)

Net cash provided by operating activities		40,568			79,463			64,732

INVESTING ACTIVITIES
Capital expenditures		(21,298	)		(8,475	)		(11,187	)
Contributions in aid of construction costs		1,826			1,567			833
Proceeds from sale of assets		9			7			19
Cash refund from prior business combination (see Note 2)								10,000
Advances to unconsolidated affiliate		(40	)		(30	)		(5	)

Cash used in investing activities		(19,503	)		(6,931	)		(340	)

FINANCING ACTIVITIES
Cash distributions to owners, net		(21,065	)		(72,532	)		(64,392	)

Cash used in financing activities		(21,065	)		(72,532	)		(64,392	)

NET CHANGE IN CASH		—			—			—
CASH, JANUARY 1		—			—			—

CASH, DECEMBER 31	$	—		$	—		$	—

See Notes to Combined Financial Statements

F-15

DUNCAN ENERGY PARTNERS PREDECESSOR

STATEMENTS OF COMBINED OWNERS’ NET INVESTMENT


	(Dollars in thousands)

Balance at January 1, 2003	$	536,065
Net income		52,454
Net cash distributions to owners		(64,392	)

Balance at December 31, 2003		524,127
Net income		58,124
Net cash distributions to owners		(72,532	)

Balance at December 31, 2004		509,719
Net income		39,087
Non-cash contribution from owner		26
Net cash distributions to owners		(21,065	)

Balance at December 31, 2005	$	527,767

See Notes to Combined Financial Statements

F-16

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS


1.	Background and Basis of Financial Statement Presentation

Unless the context requires otherwise, references to “we,” “us,” “our” or “the Company” are intended to mean and include the combined businesses and operations of Duncan Energy Partners Predecessor.

References to “Enterprise Products Partners” mean the consolidated business and operations of Enterprise Products Partners L.P. Enterprise Products Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange.

Predecessor Company

Duncan Energy Partners Predecessor is engaged in the business of (i) receiving, storing and delivering natural gas liquids (“NGLs”) and petrochemical products, (ii) gathering, transporting, storing and marketing natural gas and (iii) transporting propylene. The principal business entities included in the historical combined financial statements of Duncan Energy Partners Predecessor are (on a 100% basis): (i) Mont Belvieu Caverns, L.P. (which will be converted into a limited liability company named Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”), a Delaware limited partnership; (ii) Acadian Gas, LLC (“Acadian Gas”), a Delaware limited liability company; (iii) Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), a Delaware limited partnership, including its general partner; (iv) Sabine Propylene Pipeline L.P. (“Sabine Propylene”), a Delaware limited partnership, including its general partner; and (v) South Texas NGL Pipelines, LLC (“South Texas NGL”). The following is a brief description of the operations of each business comprising the Company including the new South Texas NGL operations to be included subsequent to these statements:


	•	Mont Belvieu Caverns owns and operates 33 salt dome caverns located in Mont Belvieu, Texas, with an underground storage capacity of approximately 100 million barrels (“MMBbls”). Mont Belvieu Caverns receives, stores and delivers NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast.

	•	Acadian Gas gathers, transports, stores and markets natural gas in Louisiana utilizing over 1,000 miles of high-pressure transmission lines and lateral and gathering lines with an aggregate throughput capacity of one Bcf/d including a 27-mile pipeline owned by its joint venture affiliate Evangeline Gas Pipeline, L.P., (“Evangeline”) and a leased storage cavern with three Bcf of storage capacity, (see Note 4).

	•	Lou-Tex Propylene owns a 263-mile pipeline used to transport chemical-grade propylene between Sorrento, Louisiana and Mont Belvieu, Texas.

	•	Sabine Propylene owns a 21-mile pipeline used to transport polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect in Cameron Parish, Louisiana on a transport-or-pay basis.

	•	South Texas NGL will own a 223-mile pipeline extending from Corpus Christi, Texas to Pasadena, Texas that was purchased by Enterprise Products Partners in August 2006 for $97.7 million. This pipeline (along with others to be constructed or acquired) will be used to transport NGLs from two of Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas beginning in January 2007. The total estimated cost to acquire and construct the additional pipelines that will complete this system is $68.6 million (unaudited), which includes an approximate $8 million (unaudited) pipeline asset purchase from an affiliate. The Company’s historical combined financial statements do not reflect any transactions related to this asset.

Basis of Financial Statement Presentation

F-17

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

prepared using Enterprise Products Partners’ historical basis in each entity’s assets and liabilities and historical results of operations. The combined financial statements may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Transactions between the Company and related parties such as Enterprise Products Partners and EPCO, Inc. (“EPCO”) have been identified in the combined statements (see Note 6).

We view the accompanying combined financial statements as the predecessor of Duncan Energy Partners L.P. (the “Partnership”), a Delaware limited partnership formed on September 29, 2006. The Partnership was formed to acquire ownership interests in Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene, Sabine Propylene and South Texas NGL. These ownership interests will be acquired by the Partnership in connection with its proposed initial public offering of common units. We believe the combined historical financial statements of the Company are relevant for investors evaluating an investment decision in the Partnership.

Our combined financial statements reflect the accounts of subsidiaries in which we have a controlling interest, after the elimination of all significant intercompany accounts and transactions. In the opinion of management, all adjustments necessary for a fair presentation of the combined financial statements, in accordance with accounting principles generally accepted in the United States of America (generally referred as “GAAP”), have been made.

The Company has operated within the Enterprise Products Partners cash management program for all periods presented. For purposes of presentation in the Statements of Combined Cash Flows, cash flows from financing activities represent transfers of excess cash from the Company to Enterprise Products Partners equal to cash provided by operations less cash used in investing activities. Such transfers of excess cash are shown as distributions to owners in the Statements of Combined Owners’ Net Investment. As a result, the combined financial statements do not present cash balances for any of the periods presented.

Because a single direct owner relationship does not exist among these combined entities, the net investment in these entities (“owners’ net investment”) is shown in lieu of parent or owners’ equity in the combined financial statements. Enterprise Products Partners indirectly owned all of the equity interests of our subsidiaries during the periods presented.

Partnership Organization

As noted previously, the Partnership will acquire ownership interests in the Company’s businesses, as specified below, from Enterprise Products Partners. Initially, the organizational limited partner of the Partnership is Enterprise Products Operating L.P. (the “Enterprise Products OLP”), which owns 98% of the Partnership. DEP Holdings, LLC (the “General Partner”) is the 2% general partner of the Partnership. The General Partner will be responsible as general partner for managing all of the Partnership’s operations and activities. EPCO will provide all employees and certain administrative services for us. Enterprise Products OLP is a wholly owned subsidiary of Enterprise Products Partners L.P. The Partnership, the General Partner, Enterprise Products OLP and Enterprise Products Partners are affiliates under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO and its affiliates. EPCO will provide employees to the General Partner, the Partnership and its subsidiaries pursuant to an administrative services agreement.

In the fourth quarter of 2006, the Partnership expects to file a registration statement for its initial public offering of limited partner common units. In connection with the initial public offering, the Partnership will acquire a 66% interest in the following companies, all of which are indirect wholly-owned subsidiaries of Enterprise Products Partners:


	•	Mont Belvieu Caverns;

	•	Acadian Gas;

	•	Lou-Tex Propylene;

F-18

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


	•	Sabine Propylene; and

	•	South Texas NGL in 2007.

Enterprise Products Partners has owned controlling interests and operated the underlying assets of Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene for several years. Enterprise Products Partners will retain the ownership interests in these four entities (as well as the recently acquired South Texas NGL) that are not being acquired by the Partnership. Enterprise Products Partners and its subsidiaries, including Enterprise Products OLP, will continue to operate the assets of each of these businesses. Enterprise Products OLP will control the Partnership’s general partner and remain a significant owner of new limited partner common unit interests in the Partnership after the initial public offering.


2.	Summary of Significant Accounting Policies

Allowance for Doubtful Accounts

Our allowance for doubtful accounts balance is generally determined based on specific identification and estimates of future uncollectible accounts, as appropriate. Our procedure for recording an allowance for doubtful accounts is based on (i) our historical experience, (ii) the financial stability of our customers and (iii) the levels of credit granted to customers. In addition, we may also increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and those experiencing other financial difficulties. We routinely review estimates used to develop this reserve to ascertain that we have recorded sufficient amounts to cover potential losses. Our allowance for doubtful accounts was $3.4 million and $3.5 million at December 31, 2005 and 2004, respectively.

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us, but which will only be resolved when one or more future events occur or fail to occur. Our management and legal counsel evaluate such contingent liabilities, and such evaluations inherently involve an exercise in judgment. In assessing loss contingencies, our legal counsel evaluates the perceived merits of legal proceedings that are pending against us and unasserted claims that may result in proceedings, if any, as well as the perceived merits of the amount of relief sought or expected to be sought therein from each.

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

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

Deferred Revenue

In our storage business, we occasionally bill customers in advance of the periods in which we provide storage services. We record such amounts as deferred revenue. We recognize these revenues ratably over the applicable service period. Our deferred revenue was $0.3 million and $1.2 million at December 31, 2005 and 2004, respectively.

F-19

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Deposits from Customers

Natural gas customers that pose a credit risk are required to make a prepayment (i.e., a deposit) to us in connection with sales transactions. Deposits from customers were $0.4 million and $4.6 million at December 31, 2005 and 2004, respectively.

Dollar Amounts

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

Earnings per Unit

We have not included earnings per unit data since we do not have any outstanding units.

Environmental Costs

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s estimate of the ultimate cost to remediate a site. Ongoing environmental compliance costs are charged to expense as incurred. Expenditures to mitigate or prevent future environmental contamination are capitalized. Our operations include activities that are subject to federal and state environmental regulations.

Expenses for environmental compliance and monitoring were $0.3 million, $0.2 million and $0.2 million during 2005, 2004 and 2003, respectively. Our reserve for environmental remediation projects totaled $0.2 million at December 31, 2005.

Equity-Based Compensation

As is commonly the case with publicly traded limited partnerships, we do not directly employ any of the persons responsible for the management and operations of our businesses. These functions are performed by employees of EPCO pursuant to an administrative services agreement (see Note 6) under the direction of the Board of Directors and executive officers of Enterprise Products OLPGP, Inc., the general partner of Enterprise Products OLP.

Certain key employees also participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of restricted units of Enterprise Products Partners and limited partner interests in EPE Unit L.P. Prior to January 1, 2006, EPCO accounted for these awards using the provisions of Accounting Principles Board Opinion 25, “Accounting for Stock Issued to Employees.” On January 1, 2006, EPCO adopted SFAS 123(R), “Accounting for Stock-Based Compensation,” to account for its equity awards.

The amount of equity-based compensation allocable to the Company’s businesses was $26 thousand for the year ended December 31, 2005.

Based on information currently available, we expect that the Partnership’s reimbursement to EPCO in connection with long-term incentive compensation plans will be immaterial to our financial position and results of operations over the next five years.

Estimates

Preparing our combined financial statements in conformity with GAAP requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during a given period. Our actual results could differ from these estimates.

F-20

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Exit and Disposal Costs

Exit and disposal costs are charges associated with an exit activity not associated with a business combination or with a disposal activity covered by Statement of Financial Accounting Standard (“SFAS”) 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Examples of these costs include (i) termination benefits provided to current employees that are involuntarily terminated under the terms of a benefit arrangement that, in substance, is not an ongoing benefit arrangement or an individual deferred compensation contract, (ii) costs to terminate a contract that is not a capital lease, and (iii) costs to consolidate facilities or relocate employees. In accordance with SFAS 146, “Accounting for Costs Associated with Exit and Disposal Activities,” we recognize such costs when they are incurred rather than at the date of our commitment to an exit or disposal plan. We have not recognized any such costs for the periods presented.

Fair Value Information

Due to their short-term nature, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair values. The fair values associated with our commodity financial instruments were developed using available market information and appropriate valuation techniques. The following table presents the estimated fair values of our financial instruments at the dates indicated:


	December 31,				December 31,
	2005				2004
	Carrying		Fair		Carrying		Fair
Financial Instruments	Value		Value		Value		Value

Financial assets:
Accounts receivable	$	110,680	$	110,680	$	68,070	$	68,070
Commodity financial instruments(1)		517		517		725		725
Financial liabilities:
Accounts payable and accrued expenses		103,613		103,613		65,016		65,016
Commodity financial instruments(1)		570		570		1,080		1,080


(1)		Represent commodity financial instrument transactions that have either (i) not settled or (ii) settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

Financial Instruments

We use financial instruments in our Acadian Gas operations, to secure certain fixed price natural gas sales contracts (referred to as “customer fixed-price arrangements”). We also enter into a limited number of cash flow hedges in connection with the Acadian Gas business. We recognize such instruments on the balance sheet as assets or liabilities based on an instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. Changes in fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met.

To qualify as a hedge, the item to be hedged must expose us to commodity price risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We formally designate such financial instruments as hedges and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness is immediately recognized in earnings. Our customer fixed-price arrangements do not qualify for hedge accounting under SFAS 133; therefore, these instruments are accounted for using a mark-to-market approach each reporting period.

F-21

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Impairment Testing for Long-Lived Assets

Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable.

Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written down to their estimated fair values in accordance with SFAS 144. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value of a long-lived asset exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge is recognized equal to the excess of the asset’s carrying value over its estimated fair value. Fair value is defined as the estimated amount at which an asset or liability could be bought or settled, respectively, in an arm’s-length transaction. We measure fair value using market prices or, in the absence of such data, appropriate valuation techniques. We had no such impairment charges during the periods presented.

Impairment Testing for Unconsolidated Affiliate

We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate that there is a potential loss in value of the investment (other than a temporary decline). Examples of such events or changes in circumstances include a history of investee operating losses or long-term adverse changes in the investee’s industry. If we determine that a loss in the investment’s value is attributable to an event other than temporary decline, we adjust the carrying value of the investment to its fair value through a charge to earnings. We had no such impairment charges during the periods presented.

Inventories

Our inventory consists of natural gas volumes valued at the lower of average cost or market, with “market” determined by industry posted prices. We capitalize as a cost of inventory shipping and handling charges directly related to volumes we purchase from third parties. As volumes are sold and delivered out of inventory, the average cost of these products is charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred.

At December 31, 2005 and 2004, the value of our natural gas inventory was $9.9 million and $4.8 million, respectively. As a result of fluctuating market conditions, we recognize lower of average cost or market (“LCM”) adjustments when the historical cost of our inventory exceeds its net realizable value. These non-cash adjustments are recorded as a component of operating costs and expenses. For the years ended December 31, 2005 and 2003, we recognized LCM adjustments of approximately $3.2 million and $1.3 million, respectively. No LCM adjustments were required during 2004.

F-22

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Investments in Unconsolidated Affiliate

We initially evaluate our ownership of financial interests in a business enterprise for consolidation consideration purposes related to variable interest entities. Then investment interests in which we own 3% to 50% and exercise significant influence over the investee’s operating and financial policies are accounted for using the equity method. If the investee is organized as a limited liability company and maintains separate ownership accounts for its members, we account for our investment using the equity method if our ownership interest is between 3% and 50%. For all other types of investees, we apply the equity method of accounting if our ownership interest is between 20% and 50%. Our proportionate share of profits and losses from transactions with our equity method unconsolidated affiliate is eliminated in combination. If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method.

We include equity earnings from our unconsolidated affiliate, Evangeline, in our measure of segment gross operating margin and combined operating income due to the integrated nature of its operations with that of Acadian Gas. See Note 4 for information regarding our equity method investment.

New accounting pronouncements

Emerging Issues Task Force (“EITF”) 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” This accounting guidance requires that two or more inventory transactions with the same counterparty be viewed as a single non-monetary 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 combined financial position, results of operations or cash flows.

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

F-23

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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 the Partnership.

Natural Gas Imbalances

Natural gas imbalances result when a customer injects more or less gas into a pipeline than it withdraws. Our imbalance receivables and payables are valued at market price. At December 31, 2005 and 2004, our imbalance receivables were $1.6 million and $1.8 million, respectively, and are reflected as a component of “Accounts receivable — trade” on our Combined Balance Sheets. At December 31, 2005 and 2004, our imbalance payable was $2.9 million and $0.5 million respectively, and is reflected as a component of “Accrued gas payables” on our Combined Balance Sheets.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost. Expenditures for major additions and improvements are capitalized and minor replacements, maintenance, and repairs are charged to expense as incurred. We use the expense-as-incurred method for planned major maintenance activities.

When property and equipment are retired or otherwise disposed of, the cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is included in results of operations for the respective period. We record depreciation over the estimated useful lives of our assets primarily using the straight-line method for financial statement purposes. We use other depreciation methods (generally accelerated) for tax purposes where appropriate.

F-24

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

We account for asset retirement obligations (“AROs”) using SFAS 143, “Accounting for Asset Retirement Obligations,” as interpreted by FIN 47, “Accounting for Conditional Asset Retirement Obligations.” Asset retirement obligations are legal obligations associated with the retirement of a tangible long-lived asset that result from the asset’s acquisition, construction, development and/or normal operation. An ARO is initially measured at its estimated fair value. Upon initial recognition of an ARO, we record an increase to the carrying amount of the related long-lived asset and an offsetting ARO liability. We depreciate the combined cost of the asset and the capitalized asset retirement obligation using a systematic and rational allocation method over the period during which the long-lived asset is expected to provide benefits. After the initial period of ARO recognition, the ARO liability will change as a result of either the passage of time or revisions to the original estimates of either the amounts of estimated cash flows or their timing. Changes due to the passage of time increase the carrying amount of the liability because there are fewer periods remaining from the initial measurement date until the settlement date; therefore, the present value of the discounted future settlement amount increases. These changes are recorded as a period cost called accretion expense. Upon settlement, our ARO obligations will be extinguished at either the recorded amount or we will incur a gain or loss on the difference between the recorded amount and the actual settlement cost.

See Note 3 for additional information regarding our property, plant and equipment and related AROs.

Provision for Income Taxes

Our entities are organized as pass-through entities for income tax purposes. As a result, the owners of such entities are responsible for federal income taxes on their share of each entity’s taxable income.

In May 2006, the State of Texas substantially revised its existing state franchise tax. The revised tax (the “Texas Margin Tax”) becomes effective for franchise tax reports due on or after January 1, 2008. In general, legal entities that conduct business in Texas and benefit from limited liability protection are subject to the Texas Margin Tax. As a result of the change in tax law, management believes that our tax status in the State of Texas will change such that we will become subject to the Texas Margin Tax. We will record an estimated deferred tax liability of $21 thousand for the Texas Margin Tax in June 2006.

Revenue Recognition

We recognize revenue using the following criteria: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyer’s price is fixed or determinable and (iv) collectibility is reasonably assured.

Our underground storage business generates revenues from contracts related to daily storage capacity reservation agreements and excess storage fees. With respect to daily storage contracts, we collect a fee based on the number of days a customer has volumes in storage multiplied by a storage rate for each product. Under these contracts, revenue is recognized ratably over the length of the storage period based on the storage fees specified in each contract. In addition, we receive revenues from the sale of brine gathering at the storage location.

With respect to capacity reservation agreements, we collect a fee for reserving space (typically in millions of barrels) for a customer’s product in our underground storage wells. Under these agreements, revenue is recognized ratably over the specified reservation period. If a customer stores less than the reservation amount, we recognize the applicable reservation fee over the term of the arrangement. We also collect excess storage fees when customers exceed their reservation amounts. Such excess storage fees are recognized in the period of occurrence. Revenues from daily storage capacity reservation agreements and excess storage fees are based upon market-related prices as determined by the individual agreements. Based on information currently available, we expect capacity reservation revenues of $28.3 million for 2006, $8.6 million for 2007, $7.3 million for 2008, $7.1 million for 2009 and $5.7 million for 2010.

F-25

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Our natural gas pipelines and services, and our petrochemical pipeline services generate revenues from transportation agreements where shippers are billed a fee per unit of volume transported (typically in MMBtus for natural gas and MBPD for petrochemicals) multiplied by the volume delivered. The transportation fees charged under these arrangements are contractual. Revenues associated with these fee-based contracts are recognized when volumes have been physically delivered to our customer through the pipeline. We also have natural gas sales contracts whereby revenue is recognized when we purchase and then resell and deliver a volume of natural gas to a customer. Revenues from these sales contracts are based upon market-related prices as determined by the individual agreements. However, prior to 2004, Sabine Propylene was regulated by the Federal Energy Regulatory Commission (“FERC”). Our Lou-Tex Propylene pipeline was also subject to the FERC’s jurisdiction until 2005. The revenues recorded by Sabine Propylene and Lou-Tex Propylene during the period in which each was regulated were based on the maximum tariff rates approved by regulatory agencies. All the petrochemical pipeline revenues are with related parties (see Note 6).

Start-Up and Organization Costs

Start-up costs and organization costs are expensed as incurred. Start-up costs are defined as one-time activities related to opening a new facility, introducing a new product or service, conducting activities in a new territory, pursuing a new class of customer, initiating a new process in an existing facility, or some new operation. Routine ongoing efforts to improve existing facilities, products or services are not start-up costs. Organization costs include legal fees, promotional costs and similar charges incurred in connection with the formation of a business. We did not record any such costs during the periods presented.

Storage gains and losses

Storage well gains and losses occur when product movements into a storage well are different than those redelivered to customers. In general, such variations result from difficulties in precisely measuring significant volumes of liquids at varying flow rates and temperatures. It is expected that substantially all product delivered into a storage well will be withdrawn over time. A measurement loss in one period is expected to be offset by a measurement gain in a subsequent period, unless product is physically lost in a storage well due to problems with cavern integrity. We did not experience any significant net losses resulting from problems with cavern integrity during the three years ended December 31, 2005.

Since we expect that storage gains and losses will approximate each other over time, storage gains or losses are charged to a storage imbalance account during the month such imbalances are created based on current pricing. The reserve is increased by measurement gains and loss accruals and decreased by measurement losses. On an annual basis, the storage imbalance reserve account is reviewed for reasonableness based on historical measurement gains and losses and adjusted accordingly through a charge to earnings. At December 31, 2005 and 2004, our storage imbalance account was $4.5 million and $3.5 million. Net measurement losses of $2.0 million, $2.2 million and $1.5 million were charged to the reserve during the years ended December 31, 2005, 2004 and 2003, respectively. Operating costs and expenses reflect well loss accruals of $3.1 million, $0.6 million and $2.4 million for the years ended December 31, 2005, 2004 and 2003, respectively.

In addition operating gains and losses due to measurement variances for product movements to and from storage wells relating primarily to pipeline and well connection activities are included in our financial statements. Many of our customer storage arrangements allow us to retain a small amount of liquid volumes to help offset any measurement losses. These variances are estimated and settled at current prices each reporting period as a net credit or charge to operating costs and expenses. We do not retain inventory volumes. The net amounts for each of the years ended December 31, 2005, 2004 and 2003 were a $2.1 million charge, $0.2 million credit and $1.4 million credit, respectively.

F-26

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Supplemental Cash Flow Information

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures based on activities initiated by the party. The majority of such arrangements are associated with projects related to pipeline construction and well tie-ins. We received $1.8 million, $1.6 million and $0.8 million as contributions in aid of our construction costs during the years ended December 31, 2005, 2004 and 2003, respectively.

We incurred liabilities for construction in progress and property additions that had not been paid at December 31, 2005, 2004 and 2003 of $4.8 million, $1.4 million and $0.2 million, respectively.

In January 2002, we acquired a number of storage wells from a third-party seller. The purchase price we paid included four wells that were later determined not usable for storage. We received a $10 million refund of the purchase price from the seller, which is reflected as “Cash refund from prior business combination” on our Statements of Combined Cash Flows.


3.	Property, Plant and Equipment

Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:


	Estimated Useful			At December 31,
	Life in Years			2005		2004

Natural gas and petrochemical pipelines and related equipment(1)		5-35	(4)	$	343,843	$	340,813
Underground storage wells and related assets(2)		5-35	(5)		260,976		251,858
Transportation equipment(3)		3-10			1,102		923
Land					14,743		14,689
Construction in progress					15,063		3,259

Total					635,727		611,542
Less accumulated depreciation					123,530		104,428

Property, plant and equipment, net				$	512,197	$	507,114


(1)		Includes natural gas and petrochemical pipelines, office furniture and equipment, buildings, and related assets.

(2)		Underground storage facilities include underground product storage caverns and related integral specific assets such as pipes and compressors.

(3)		Transportation equipment includes vehicles and similar assets used in our various operations.

(4)		In general, the estimated useful lives of major components of this category are: pipelines, 18-35 years (with some equipment at 5 years); office furniture and equipment, 3-20 years; and buildings 20-35 years.

(5)		In general, the estimated useful live of underground storage facilities is 20-35 years (with some components at 5 years).

Depreciation expense for the years ended December 31, 2005, 2004 and 2003 was $19.2 million, $18.1 million and $17.6 million, respectively.

At December 31, 2005, we recorded conditional AROs in connection with certain right-of-way agreements, leases and regulatory requirements. Conditional AROs are obligations in which the timing and/or amount of settlement are uncertain. None of our assets are legally restricted for purposes of settling AROs. Our accrued liability for AROs was approximately $0.6 million at December 31, 2005.

F-27

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

We recorded a cumulative effect of a change in accounting principle of $0.6 million in connection with our implementation of FIN 47 in December 2005, which represents the depreciation and accretion expense we would have recognized had we recorded these conditional AROs when incurred. The pro forma effects of our adoption of FIN 47 are not presented due to the immaterial nature of these amounts to our financial statements. Based on information currently available, we estimate that annual accretion expense will approximate $0.1 million for each of the years 2006 through 2010.


4.	Investments in and Advances to Unconsolidated Affiliate — Evangeline

Acadian Gas, through a wholly owned subsidiary, owns a collective 49.51% equity interest in Evangeline, which consists of a 45% direct ownership interest in Evangeline Gas Pipeline, L.P. (“EGP”) and a 45.05% direct interest in Evangeline Gas Corp. (“EGC”). EGC also owns a 10% direct interest in EGP. Third parties own the remaining equity interests in EGP and EGC. Acadian Gas does not have a controlling interest in the Evangeline entities, but does exercise significant influence on Evangeline’s operating policies. Acadian Gas accounts for its financial investment in Evangeline using the equity method since it is not the primary beneficiary of a variable interest.

At December 31, 2005 and 2004, the carrying value of our investment in Evangeline was $2.4 million and $2.0 million, respectively. Our Combined Statements of Operations reflect equity earnings from Evangeline of $0.3 million, $0.2 million and $0.1 million for the years ended December 31, 2005, 2004 and 2003, respectively. Our investment in Evangeline is classified within our Natural Gas Pipelines & Services business segment.

Evangeline owns a 27-mile natural gas pipeline system extending from Taft, Louisiana to Westwego, Louisiana that connects three electric generation stations owned by Entergy Louisiana (“Entergy”). Evangeline’s most significant contract is a 21-year natural gas sales agreement with Entergy. Evangeline is obligated to make available-for-sale and deliver to Entergy certain specified minimum contract quantities of natural gas on an hourly, daily, monthly and annual basis. The sales contract provides for minimum annual quantities of 36.75 billion British thermal units (“Bbtus”), until the contract expires on January 1, 2013. Quantities delivered to Entergy for the years ended December 31, 2005, 2004 and 2003 under the contract totaled 37.61 Bbtus, 36.75 Bbtus and 36.75 Bbtus, respectively.

The sales contract contains provisions whereby Entergy is obligated to pay Evangeline a minimum fee each period, whether or not it is able to take delivery of natural gas volumes. The following table presents these minimum amounts for the annual periods presented:


2006	$	7,008
2007		6,507
2008		6,478
2009		6,450
2010		6,421
Thereafter		12,755

Total	$	45,619

In connection with the Entergy sales contract, Evangeline has entered into a natural gas purchase contract with Acadian Gas that contains annual purchase provisions. The minimum annual purchase quantities under this contract correspond to the aforementioned Entergy natural gas sales contract. The pricing terms of the sales agreement with Entergy and Evangeline’s purchase agreement with Acadian Gas are based on a weighted-average cost of natural gas each month (subject to certain market index price ceilings and incentive margins) plus a predetermined margin. Due to this pricing methodology, Evangeline’s monthly net sales margin under the Entergy gas sales contract is essentially fixed.

F-28

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Entergy has the option to purchase the Evangeline pipeline system or an equity interest in Evangeline. In 1991, Evangeline entered into an agreement with Entergy whereby Entergy was granted the right to acquire Evangeline’s pipeline system for a nominal price, plus the complete performance and compliance with the natural gas sales contract. The option period begins the earlier of July 1, 2010 or upon the payment in full of Evangeline’s Series B notes as discussed below. It terminates on December 31, 2012. We cannot ascertain when, or if, Entergy will exercise this option. This uncertainty results from factors which include Entergy’s management decisions and regulatory approvals that may be required for Entergy to acquire Evangeline’s assets at the time the option is exercisable.

At December 31, 2005, long-term debt for Evangeline consisted of (i) $23.2 million in principal amount of 9.9% fixed interest rate senior secured notes due December 2010 (the “Series B” notes) and (ii) a $7.5 million subordinated note payable to an affiliate of the other co-venture participant (the “ENC Note”). The Series B notes are collateralized by (i) Evangeline’s property, plant and equipment; (ii) proceeds from its Entergy natural gas sales contract; and (iii) a debt service reserve requirement. Scheduled principal repayments on the Series B notes are $5 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. The trust indenture governing the Series B notes contains covenants such as requirements to maintain certain financial ratios. Evangeline was in compliance with such covenants during the periods presented.

Evangeline incurred the ENC Note obligations in connection with its acquisition of the Entergy natural gas sales contract in 1991 and formation of the venture. The ENC Note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B note holders are either fully cash secured through debt service accounts or have been completely repaid. Variable rate interest accrues on the subordinated note at a LIBOR rate plus 0.5%. Variable interest rates charged on this note at December 31, 2005 and 2004 were 4.23% and 1.83%, respectively. At December 31, 2005 and 2004, the amount of accrued but unpaid interest on the ENC Note is approximately $7.1 and $6.6 million, respectively.

Summarized financial information of Evangeline is presented below.


	At December 31
	2005		2004

Balance sheet data:
Current assets	$	35,918	$	20,908
Property, plant and equipment, net		7,190		8,189
Noncurrent assets		33,950		37,558

Total assets	$	77,058	$	66,655

Current liabilities	$	37,876	$	23,525
Noncurrent liabilities		32,737		37,210
Combined equity		6,445		5,920

Total liabilities and combined equity	$	77,058	$	66,655


	For Year Ended December 31
	2005		2004		2003

Income statement data:
Revenues	$	340,361	$	250,757	$	223,638
Operating income		3,563		3,752		4,209
Net income		526		231		291

F-29

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


5.	Intangible Assets

At December 31, 2005 and 2004, our intangible assets consisted primarily of renewable storage contracts with various customers that we acquired in connection with the purchase of storage caverns from a third party in January 2002. Due to the renewable nature of these contracts, we amortize them on a straight-line basis over the estimated remaining economic life of the storage assets to which they relate.

The gross value of these intangible assets was $8.1 million at inception. At December 31, 2005 and 2004, the carrying values of these intangible assets were $7.2 million and $7.4 million, respectively. We recorded $0.2 million in amortization expense associated with these intangible assets for all periods presented. Based on information currently available, we estimate that amortization expense associated with existing intangible assets will approximate $0.2 million per year for each of the years 2006 through 2010.


6.	Related Party Transactions

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


	For Year Ended December 31
	2005		2004		2003

Revenues
Enterprise Products Partners and affiliates	$	87,307	$	79,611	$	73,418
Evangeline		331,522		241,400		214,200

Total	$	418,829	$	321,011	$	287,618

Operating costs and expenses
EPCO	$	35,659	$	25,609	$	25,314
Enterprise Products Partners and affiliates		25,315		3,801
Evangeline		4				4

Total	$	60,978	$	29,410	$	25,318

General and administrative costs
EPCO	$	3,937	$	4,228	$	4,901

Relationship with Enterprise Products Partners

Enterprise Products Partners was the shipper of record on our Sabine Propylene and Lou-Tex Propylene pipelines. We recorded $33.9 million, $40.9 million and $42.3 million of related party pipeline transportation revenues from Enterprise Products Partners on these pipelines for the years ended December 31, 2005, 2004 and 2003, respectively. For the periods in which Sabine Propylene and Lou-Tex Propylene were subject to FERC regulations, such related party revenues were based on the maximum tariff rate allowed for each system. We continued to charge Enterprise Products Partners such maximum transportation rates after both entities were declared exempt from FERC oversight.

Enterprise Products Partners has entered into agreements with third parties involving use of the Sabine Propylene and Lou-Tex Propylene pipelines. Enterprise Products Partners recorded $15.4 million, $14.2 million and $15.1 million in revenues for the years ended December 31, 2005, 2004 and 2003, respectively, in connection with such agreements. Apart from such agreements, Enterprise Products Partners did not utilize the Sabine Propylene and Lou-Tex Propylene assets. Enterprise Products Partners has assigned certain agreements with third parties involving the use of our Sabine Propylene and Lou-Tex Propylene pipelines to us but remains jointly and severally liable on those agreements.

F-30

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Our related party revenues from Enterprise Products Partners and affiliates also include the sale of natural gas of $35.8 million, $21.7 million and $13.8 million for the years ended December 31, 2005, 2004 and 2003, respectively. Our related party operating costs and expenses include the cost of natural gas Enterprise Products Partners sold to us. Such amounts were $25.3 million, $3.8 million and none for the years ended December 31, 2005, 2004 and 2003, respectively. In addition, Enterprise Products Partners has furnished letters of credit on behalf of Evangeline’s debt service requirements. At December 31, 2005, such outstanding letters of credit totaled $1.2 million.

We also provide underground storage services to Enterprise Products Partners for the storage of NGLs and petrochemicals. At December 31, 2005, 2004 and 2003, we record $17.6 million, $17.0 million and $17.3 million, respectively, in storage revenue from Enterprise Products Partners.

We expect that certain commercial arrangements with Enterprise Products Partners will change once the Partnership completes its initial public offering. These changes will include:


	•	The reduction in transportation rates previously charged by us to Enterprise Products Partners for usage of the Lou-Tex Propylene and Sabine Propylene pipelines to the levels Enterprise Products Partners realizes from the third-party shippers on these systems.

	•	An increase in storage fees charged Enterprise Products Partners by Mont Belvieu Caverns related to the storage activities of Enterprise Products Partners’ octane enhancement, isomerization and NGL and petrochemical marketing businesses. Historically, such intercompany charges were below market and eliminated in the consolidated revenues and costs and expenses of Enterprise Products Partners. Prospectively, such rates will be market-related.

	•	The well measurement gains and losses associated with products delivered by Enterprise Products Partners under storage agreements with us will be allocated to Enterprise Products Partners. In addition, in connection with its retained equity investment in Mont Belvieu Caverns, Enterprise Products Partners will be specially allocated measurement gains and losses. See Note 2 for additional information regarding our storage gains and losses.

Relationship with EPCO

We have no employees. All of our operating functions are performed by employees of EPCO pursuant to an administrative services agreement. EPCO also provides general and administrative support services to us in accordance with the administrative services agreement. We, Enterprise Products Partners and the other affiliates of EPCO are parties to the administrative services agreement. The significant terms of the administrative services agreement are as follows:


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

	•	We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including EPCO expenses reasonably allocated to us). In addition, we have agreed to pay all sales,

F-31

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


		use, excise, value added or similar taxes, if any, which may be applicable with respect to services provided by EPCO.


	•	EPCO allows us to participate as named insureds in its overall insurance program with the associated premiums and related costs being allocated to us. We reimbursed EPCO $1.7 million, $2.3 million and $2.2 million for insurance costs for the years ended December 31, 2005, 2004 and 2003, respectively.

	•	Our operating costs and expenses for the years ended December 31, 2005, 2004 and 2003 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Our reimbursements to EPCO for operating costs and expenses were $35.7 million, $25.6 million and $25.3 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Likewise, our general and administrative costs include amounts we reimburse to EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to administrative services agreement based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). Our reimbursements to EPCO for general and administrative costs were $3.9 million, $4.2 million and $4.9 million for the years ended December 31, 2005, 2004 and 2003, respectively.

A small number of key employees devote a portion of their time to the Company’s operations and affairs and participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of restricted units of Enterprise Products Partners and limited partner interests in EPE Unit L.P. The amount of equity-based compensation allocable to the Company’s businesses was $26 thousand for the year ended December 31, 2005. Such amount is immaterial to our combined financial position, results of operations and cash flows.

Relationships with Evangeline

We sell natural gas to Evangeline, which, in turn, uses such natural gas to satisfy its sales commitments to Entergy. Our sales of natural gas to Evangeline totaled $331.5 million, $241.4 million and $214.2 million for the years ended December 31, 2005, 2004 and 2003, respectively.

Additionally, we have a service agreement with Evangeline whereby we provide Evangeline with construction, operations, maintenance and administrative support related to its pipeline system. Evangeline paid us $0.4 million, $0.5 million and $0.4 million for such services for the years ended December 31, 2005, 2004 and 2003, respectively.


7.	Business Segments

We classify our midstream energy operations in three reportable business segments: NGL & Petrochemical Storage Services, Natural Gas Pipelines & Services, and Petrochemical Pipeline Services. We will report an additional business segment, NGL Pipeline Services, in the future to encompass our South Texas NGL pipeline business. Our business segments are generally organized and managed according to the type of services rendered (or technology employed) and products produced and/or sold.

F-32

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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 combined) segment gross operating margin as operating income before: (i) depreciation, amortization and accretion expense; (ii) gains and losses on the sale of assets; and (iii) 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 any intersegment and intrasegment transactions. Our combined revenues reflect the elimination of all material intercompany transactions.

We include equity earnings from Evangeline in our measurement of segment gross operating margin and operating income. Our equity investments in midstream energy operations such as those conducted by Evangeline are a vital component of our long-term business strategy and important to the operations of Acadian Gas. This method of operation enables us to achieve favorable economies of scale relative to our level of investment and also lowers our exposure to business risks compared the profile we would have on a stand-alone basis. Our equity investments are within the same industry as our combined operations, thus we believe treatment of earnings from our equity method investee as a component of gross operating margin and operating income is appropriate.

Our combined revenues were earned in the United States. Our underground storage wells in Southeast Texas receive, store and deliver NGLs and petrochemical products for refinery and other customers along the upper Texas Gulf Coast. Our Acadian Gas operations gather, transport, store and market natural gas to customers primarily in Louisiana. Our petrochemical pipelines provide propylene transportation services to shippers in southeast Texas and southwestern Louisiana.

Combined property, plant and equipment and investments in and advances to our unconsolidated affiliate are allocated to each segment based on the primary operations of each asset or investment. The principal reconciling item between combined property, plant and equipment and the total value of segment assets is construction-in-progress. Segment assets represent the net carrying value of assets that contribute to the gross operating margin of a particular segment. Since assets under construction generally do not contribute to segment gross operating margin until completed, such assets are excluded from segment asset totals until they are deemed operational.

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


	Year Ended December 31,
	2005			2004			2003

Revenues(1)	$	953,397		$	748,931		$	668,234
Less: Operating costs and expenses(1)		(909,044	)		(685,544	)		(609,774	)
Add: Equity in income of unconsolidated affiliate(1)		331			231			131
Depreciation, amortization and accretion in operating costs and expenses(2)		19,453			18,374			17,882
Gain (loss) on sale of assets in operating costs and expenses(2)		5			(7	)

Total segment gross operating margin	$	64,142		$	81,985		$	76,473

F-33

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


(1)		These amounts are taken from our Statements of Combined Operations and Comprehensive Income.

(2)		These non-cash expenses are taken from the operating activities section of our Statements of Combined Cash Flows.

A reconciliation of total segment gross operating margin to operating income and income before the cumulative effect of a change in accounting principle follows:


	Year Ended December 31,
	2005			2004			2003

Total segment gross operating margin	$	64,142		$	81,985		$	76,473
Adjustments to reconcile total segment gross operating margin to operating income:
Depreciation, amortization and accretion in operating costs and expenses		(19,453	)		(18,374	)		(17,882	)
Loss (gain) on sale of assets in operating costs and expenses		(5	)		7
General and administrative costs		(4,483	)		(5,442	)		(6,138	)

Combined operating income		40,201			58,176			52,453
Other (income) expense, net		(532	)		(52	)		1

Income before cumulative effect of change in accounting principle	$	39,669		$	58,124		$	52,454

F-34

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Information by segment, together with reconciliations to the combined total revenues and expenses, is presented in the following tables:


	NGL &
	Petrochemical		Natural Gas		Petrochemical		Construction-
	Storage		Pipelines		Pipeline		in-		Combined
	Services		& Services		Services		Progress		Totals

Revenues from third parties:
Year ended December 31, 2005	$	35,237	$	499,331					$	534,568
Year ended December 31, 2004		32,555		395,365						427,920
Year ended December 31, 2003		32,106		348,510						380,616
Revenues from related parties:
Year ended December 31, 2005		17,601		367,362	$	33,866				418,829
Year ended December 31, 2004		16,979		263,057		40,975				321,011
Year ended December 31, 2003		17,281		227,969		42,368				287,618
Total revenues:
Year ended December 31, 2005		52,838		866,693		33,866				953,397
Year ended December 31, 2004		49,534		658,422		40,975				748,931
Year ended December 31, 2003		49,387		576,479		42,368				668,234
Equity in income of unconsolidated affiliate:
Year ended December 31, 2005				331						331
Year ended December 31, 2004				231						231
Year ended December 31, 2003				131						131
Gross operating margin by individual business segment and in total:
Year ended December 31, 2005		16,636		18,939		28,567				64,142
Year ended December 31, 2004		19,843		25,256		36,886				81,985
Year ended December 31, 2003		19,838		18,272		38,363				76,473
Segment assets — property, plant and equipment:
At December 31, 2005		191,757		211,045		94,332	$	15,063		512,197
At December 31, 2004		191,325		215,015		97,515		3,259		507,114
Investments in and advances to unconsolidated affiliate (see Note 4):
At December 31, 2005				2,375						2,375
At December 31, 2004				2,003						2,003

F-35

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The following table provides additional information regarding our combined revenues and costs and expenses for the periods indicated:


	For Year Ended December 31,
	2005			2004		2003

Combined revenues
Sales of natural gas	$	858,087		$	649,889	$	569,437
Transportation — natural gas		8,606			8,533		7,042
Transportation — petrochemicals		33,866			40,975		42,368
Storage		52,838			49,534		49,387

Total	$	953,397		$	748,931	$	668,234

Combined cost and expenses
Cost of natural gas sales	$	836,497		$	623,531	$	546,717
Operating expenses		53,099			43,632		45,175
Depreciation, amortization and accretion		19,453			18,374		17,882
Gain/(losses) on sale of assets		(5	)		7
General and administrative costs		4,483			5,442		6,138

Total	$	913,527		$	690,986	$	615,912

Revenues from the purchase and resale of natural gas included in Natural Gas Pipelines & Services segment, accounted for 90%, 87% and 85% of total combined revenues for the years ended December 31, 2005, 2004 and 2003, respectively. The cost of natural gas sales accounted for 92%, 91% and 90% of total combined operating costs and expenses for the years ended December 31, 2005, 2004 and 2003, respectively.

Revenues from Enterprise Products Partners accounted for 9%, 11% and 11% of total combined revenues for the years ended December 31, 2005, 2004 and 2003, respectively. Enterprise Products Partners accounted for 100% of the revenues recorded by our Petrochemical Pipeline Services segment. Storage revenues from Enterprise Products Partners accounted for 33%, 34% and 35% of NGL & Petrochemical Storage Services segment in 2005, 2004 and 2003, respectively.

Revenues from Evangeline, our unconsolidated affiliate (see Note 4), accounted for 35%, 32% and 32% of total combined revenues for the years ended December 31, 2005, 2004 and 2003, respectively. See Note 6 for information regarding our related party transactions.

We did not have any third party customers that exceeded 10% of our combined revenues for 2005; however, ExxonMobil Gas & Power Marketing Company (“EOM”) accounted for 9.3% of Natural Gas Pipelines & Services segment revenue and 9.1% of combined revenues. In 2004, CF Industries, Inc. accounted for 12% of Natural Gas Pipelines & Services segment revenue and 11% of combined revenues. In 2003, EOM accounted for 13% of Natural Gas Pipelines & Services segment revenue and 12% of combined revenues.


8.	Financial Instruments

In addition to its natural gas transportation business, Acadian Gas engages in the purchase and sale of natural gas to third party customers in the Louisiana area. The price of natural gas fluctuates in response to changes in supply, market uncertainty, and a variety of additional factors that are beyond our control. We may use commodity financial instruments such as futures, swaps and forward contracts to mitigate such risks. In general, the types of risks we attempt to hedge are those related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices. The commodity financial instruments we utilize

F-36

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

may be settled in cash or with another financial instrument. As a matter of policy, we do not use financial instruments for speculative (or “trading”) purposes.

Acadian Gas enters into a small number of cash flow hedges in connection with its purchase of natural gas held-for-sale. In addition, Acadian Gas enters into a limited number of offsetting financial instruments that effectively fix the price of natural gas for certain of its customers. Historically, the use of commodity financial instruments by Acadian Gas was governed by policies established by the general partner of Enterprise Products Partners. The objective of this policy was to assist Acadian Gas in achieving its profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by the general partner. In general, Acadian Gas may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to its commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months.

The general partner of Enterprise Products Partners monitored the hedging strategies associated with the physical and financial risks of Acadian Gas (such as those mentioned previously), approved specific activities subject to the policy (including authorized products, instruments and markets) and established specific guidelines and procedures for implementing and ensuring compliance with the policy. DEP Holdings, our general partner, will continue such policies in the future.


9.	Commitments and Contingencies

Litigation

On occasion, we are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. Although we 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 activity.

In 1997, Acadian Gas, along with numerous other energy companies, was named a defendant in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value, as well as the volumes, of natural gas produced from federal and Native American lands. The complaint alleges that the U.S. Government was deprived of royalties as a result of this conspiracy. The plaintiff in this case seeks royalties that he contends the U.S. government should have received had the heating value and volume been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). On October 20, 2006, the U.S. District Court dismissed all of Grynberg’s claims with prejudice.

We are not aware of any other significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.

F-37

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Redelivery Commitments

We transport and store natural gas and store NGL and petrochemical products for third parties under various contracts. Under the terms of these agreements, we are generally required to redeliver volumes to the owner on demand. We are insured for any physical loss of such volumes resulting from catastrophic events. At December 31, 2005 and 2004, NGL and petrochemical products aggregating 15.2 million barrels and 13.5 million barrels, respectively, were due to be redelivered to their owners along with 730 billion BBtus and 728 BBtus, respectively, of natural gas.

Contractual Obligations

The following table summarizes our significant contractual obligations at December 31, 2005.


	Payment or Settlement Due by Period
			Less Than		1-3		3-5		More Than
Contractual Obligations	Total		1 Year		Years		Years		5 Years
			(2006)		(2007-2008)		(2009-2010)		Beyond 2010

Operating leases:
Underground natural gas storage cavern	$	3,276	$	468	$	936	$	936	$	936
Right-of-way agreements	$	533	$	79	$	159	$	26	$	269
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Natural gas	$	1,214,413	$	173,352	$	347,179	$	346,704	$	347,178
Other	$	5,983	$	1,710	$	3,425	$	848
Underlying major volume commitments:
Natural gas (in BBtus)		102,280		14,600		29,240		29,200		29,240
Capital expenditure commitments	$	616	$	616
Other long-term liabilities	$	608							$	608

Total	$	1,225,429	$	176,225	$	351,699	$	348,514	$	348,991

Acadian Gas leases an underground natural gas storage cavern that is integral to its operations. The primary use of this cavern is to store natural gas held-for-sale on a demand basis by Acadian Gas. The current term of the cavern lease expires in December 2012. The term of this contract does not provide for an additional renewal period, but it requires the lessor to enter into negotiations with us under similar terms and conditions if we wish to extend the lease agreement beyond December 2012.

F-38

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets attributable to our operations are charged to expense as incurred. We have not made any significant leasehold improvements during the periods presented. Lease expense included in operating income was $1.2 million for each of the years ended December 31, 2005, 2004 and 2003.

Acadian Gas has a product purchase commitment for the purchase of natural gas in Louisiana from the co-venture party in Evangeline (see Note 4). This purchase agreement expires in January 2013. Our purchase price under this contract approximates the market price of natural gas at the time we take delivery of the volumes. The preceding table shows the volume we are committed to purchase and an estimate of our future payment obligations for the periods indicated. Our estimated future payment obligations are based on the contractual price at December 31, 2005 applied to all future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery.

At December 31, 2005, we do not have any product purchase commitments with fixed or minimum pricing provisions having remaining terms in excess of one year.


10.	Significant Risks and Uncertainties

Nature of Operations

Our combined results of operations, cash flows and financial position may be adversely affected by a variety of factors affecting our industry and specific businesses, including:


	•	a reduction in demand for NGL and petrochemical storage services provided by Mont Belvieu Caverns caused by fluctuations in NGL and petrochemical prices and production due to weather and other natural and economic forces;

	•	a reduction in demand for natural gas transportation services and natural gas consumption in the areas served by Acadian Gas; or

	•	a reduction in propylene transportation volumes by shippers on the petrochemical pipelines owned by Lou-Tex Propylene and Sabine Propylene.

In general, a reduction in demand for NGL and petrochemical products and natural gas by the petrochemical, refining or heating industries could result from (i) a general downturn in economic conditions, (ii) reduced demand by consumers for the end products made with products we handle, (iii) increased governmental regulations or (iv) other reasons.

F-39

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Credit Risk Due to Industry Concentration

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

Counterparty Risk with Respect to Financial Instruments

In those situations where we are exposed to credit risk in our financial instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral nor do we anticipate nonperformance by our counterparties.

Weather-Related Risks

Our assets are located along the U.S. Gulf Coast in Texas and Louisiana, which are areas prone to suffer tropical weather events such as hurricanes. If we were to experience a significant weather-related loss for which we were not fully insured, it could have a material impact on our combined financial position, results of operations and cash flows. Likewise, if any of our significant customer or supplier groups experience losses related to storm events, it could have a material impact on our combined financial position, results of operations and cash flows.

F-40

SCHEDULE II

DUNCAN ENERGY PARTNERS PREDECESSOR

VALUATION AND QUALIFYING ACCOUNTS


			Additions
	Balance at		Charged to		Charged to
	Beginning		Costs and		Other				Balance at End
Description	of Period		Expenses		Accounts	Deductions			of Period

Accounts receivable — trade
Allowance for doubtful accounts
2005	$	3,457				$	(85	)	$	3,372
2004(1)		6,935					(3,478	)		3,457
2003		6,935								6,935
Other current liabilities
Reserve for environmental liabilities
2005(2)			$	150						150


(1)		In 2004, we adjusted the allowance account for the receipt of a contingent asset related to a prior business acquisition.

(2)		In 2005, Acadian Gas identified a remediation site in Ascension Parish, Louisiana. Remediation activities are scheduled to begin in 2006.

* * * *

F-41

DUNCAN ENERGY PARTNERS PREDECESSOR

UNAUDITED CONDENSED

COMBINED BALANCE SHEETS


	June 30,		December 31,
	2006		2005
	(Dollars in thousands)

ASSETS
Current assets
Accounts receivable — trade, net of allowance for doubtful accounts of $1,304 and $3,372 at June 30, 2006 and December 31, 2005, respectively	$	63,166	$	110,680
Inventories		13,636		9,855
Prepaid and other current assets		120		535

Total current assets		76,922		121,070
Property, plant and equipment, net		539,929		512,197
Investments in and advances to unconsolidated affiliate		2,788		2,375
Intangible assets, net of accumulated amortization of $1,045 at June 30, 2006 and $929 at December 31, 2005		7,082		7,198

Total assets	$	626,721	$	642,840


LIABILITIES AND OWNERS’ NET INVESTMENT
Current liabilities
Accounts payable — trade	$	903	$	1,171
Accrued gas payables		55,928		101,475
Accrued costs and expenses		3,612		967
Deposits from customers		41		357
Other current liabilities		7,645		10,495

Total current liabilities		68,129		114,465
Other long-term liabilities		658		608
Commitments and contingencies
Owners’ net investment		557,934		527,767

Total liabilities and owners’ net investment	$	626,721	$	642,840

See Notes to Unaudited Condensed Combined Financial Statements

F-42

DUNCAN ENERGY PARTNERS PREDECESSOR

UNAUDITED CONDENSED

STATEMENTS OF COMBINED OPERATIONS AND COMPREHENSIVE INCOME


	For the					For the
	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2006			2005		2006			2005
	(Dollars in thousands)

REVENUES
Related parties	$	103,707		$	94,474	$	207,291		$	170,134
Third parties		117,021			120,379		296,500			229,895

Total revenues		220,728			214,853		503,791			400,029

COST AND EXPENSES
Operating costs and expenses Related parties		11,455			12,928		24,650			21,140
Third parties		196,788			190,521		453,936			356,639

Total operating costs and expenses		208,243			203,449		478,586			377,779

General and administrative costs Related parties		950			904		1,703			1,920
Third parties		9			237		32			516

Total general and administrative costs		959			1,141		1,735			2,436

Total costs and expenses		209,202			204,590		480,321			380,215

EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATE		200			144		354			197

OPERATING INCOME		11,726			10,407		23,824			20,011

OTHER INCOME (EXPENSE), NET							4

INCOME BEFORE PROVISION FOR INCOME TAXES AND CHANGE IN ACCOUNTING PRINCIPLE		11,726			10,407		23,828			20,011
Provision for income taxes		(21	)				(21	)

INCOME BEFORE CHANGE IN ACCOUNTING PRINCIPLE		11,705			10,407		23,807			20,011
Cumulative effect of change in accounting principle							9

NET INCOME		11,705			10,407		23,816			20,011
Change in fair value of commodity hedges		54					(18	)

COMPREHENSIVE INCOME	$	11,759		$	10,407	$	23,798		$	20,011

See Notes to Unaudited Condensed Combined Financial Statements

F-43

DUNCAN ENERGY PARTNERS PREDECESSOR

UNAUDITED CONDENSED

STATEMENTS OF COMBINED CASH FLOWS


	For the
	Six Months Ended
	June 30,
	2006			2005
	(Dollars in thousands)

OPERATING ACTIVITIES
Net income	$	23,816		$	20,011
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion in operating costs and expenses		10,149			9,432
Equity in income of unconsolidated affiliate		(354	)		(197	)
Cumulative effect of change in accounting principle		(9	)
Gain on sale of assets		(13	)		(1	)
Deferred income tax expense		21
Changes in fair market value of financial instruments		(53	)		3
Effect of changes in operating accounts:
Accounts receivable		47,513			1,555
Inventories		(3,782	)		(1,908	)
Prepaid and other current assets		368			230
Other assets		(10	)
Accounts payable		(269	)		9
Accrued gas payable		(45,545	)		(2,421	)
Accrued expenses		(1,872	)		221
Deposits from customers		(316	)		(2,795	)
Other current liabilities		(2,756	)		(463	)
Other long-term liabilities		(12	)

Net cash provided by operating activities		26,876			23,676

INVESTING ACTIVITIES
Capital expenditures		(33,564	)		(10,307	)
Contributions in aid of construction costs		383			994
Proceeds from sale of assets		13			7
Advances to unconsolidated affiliate		(59	)		(103	)

Cash used in investing activities		(33,227	)		(9,409	)

FINANCING ACTIVITIES
Cash contributions from (distributions to) owners, net		6,351			(14,267	)

Cash provided by (used in) financing activities		6,351			(14,267	)

NET CHANGE IN CASH		—			—
CASH, JANUARY 1		—			—

CASH, DECEMBER 31	$	—		$	—

See Notes to Unaudited Condensed Combined Financial Statements

F-44

DUNCAN ENERGY PARTNERS PREDECESSOR

UNAUDITED CONDENSED

STATEMENTS OF COMBINED OWNERS’ NET INVESTMENT


	(Dollars in thousands)

Balance at December 31, 2005	$	527,767
Net income		23,816
Non-cash contributions from owners		18
Net cash contributions from owners		6,351
Accumulated other comprehensive loss		(18	)

Balance at June 30, 2006	$	557,934

See Notes to Unaudited Condensed Combined Financial Statements

F-45

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS


1.	Background and Basis of Financial Statement Presentation

In our opinion, the accompanying unaudited condensed combined 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. These unaudited interim period financial statements should be read in conjunction with the audited combined financial statements of the Company included elsewhere in this prospectus.

Predecessor Company

Duncan Energy Partners Predecessor (the “Company”) is engaged in the business of (i) receiving, storing and delivering natural gas liquids (“NGLs”) and petrochemical products, (ii) gathering, transporting, storing and marketing natural gas and (iii) transporting propylene. The principal business entities included in the historical combined financial statements of Duncan Energy Partners Predecessor are (on a 100% basis): (i) Mont Belvieu Caverns, L.P. (which will be converted into a limited liability company named Mont Belvieu Caverns, LLC) (“Mont Belvieu Caverns”), a Delaware limited partnership; (ii) Acadian Gas, LLC (“Acadian Gas”), a Delaware limited liability company; (iii) Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), a Delaware limited partnership, including its general partner; (iv) Sabine Propylene Pipeline L.P. (“Sabine Propylene”), a Delaware limited partnership, including its general partner; and (v) South Texas NGL Pipelines, LLC (“South Texas NGL”). The following is a brief description of the operations of each business comprising the Company including the new South Texas NGL operations to be included subsequent to these statements:


	•	Mont Belvieu Caverns owns and operates 33 salt dome caverns located in Mont Belvieu, Texas, with an underground storage capacity of approximately 100 million barrels (“MMBbls”). Mont Belvieu Caverns receives, stores and delivers NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast.

	•	Acadian Gas gathers, transports, stores and markets natural gas in Louisiana utilizing over 1,000 miles of high-pressure transmission lines and lateral and gathering lines with an aggregate throughput capacity of one Bcf/d, including a 27-mile pipeline owned by its Evangeline affiliate, and a leased storage cavern with storage capacity of three Bcf. (see Note 4).

	•	Lou-Tex Propylene owns a 263-mile pipeline used to transport chemical-grade propylene between Sorrento, Louisiana and Mont Belvieu, Texas.

	•	Sabine Propylene owns a 21-mile pipeline used to transport polymer-grade propylene from Port Arthur, Texas to a pipeline interconnect in Cameron Parish, Louisiana on a transportation-or-pay basis.

	•	South Texas NGL will own a 223-mile pipeline extending from Corpus Christi, Texas to Pasadena, Texas that was purchased by Enterprise Products Partners in August 2006 for $97.7 million. This pipeline (along with others to be constructed or acquired) will be used to transport NGLs from two of Enterprise Products Partners’ facilities located in South Texas to Mont Belvieu, Texas beginning in

F-46


		DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)


		January 2007. The estimated cost to acquire and construct the additional pipelines that will complete this system is $68.6 million. The Company’s historical combined financial statements do not reflect any transactions related to this asset prior to its acquisition since it was not operational.

Basis of Financial Statement Presentation

The accompanying combined financial statements and related notes of the Company have been prepared from Enterprise Products Partners’ separate historical accounting records related to Mont Belvieu Caverns, Acadian Gas, Lou-Tex Propylene and Sabine Propylene. These combined financial statements have been prepared using Enterprise Products Partners historical basis in each entity assets and liabilities and historical results of operations. The combined financial statements may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Transactions between the Company and related parties such as Enterprise Products Partners have been identified in the combined statements (see Note 6).

The Company has operated within the Enterprise Products Partners cash management program for all periods presented. For purposes of presentation in the Statements of Combined Cash Flows, cash flows from financing activities represent transfers of excess cash from the Company to Enterprise Products Partners and shortfall contributions from Enterprise Products Partners to the Company are equal to cash provided by operations less cash used in investing activities. Such transfers of excess and shortfalls of cash are shown as distributions to or contributions from owners in the Statements of Combined Owners’ Net Investment. As a result, the combined financial statements do not present cash balances for any of the periods presented.

Partnership Organization

As noted previously, the Partnership will acquire ownership interests in the Company’s businesses, as specified below, from Enterprise Products Partners. Initially, the organizational limited partner of the Partnership is Enterprise Products Operating, LP ( “Enterprise Products OLP”), which owns 98% of the Partnership. DEP Holdings, LLC (the “General Partner”) is the 2% general partner of the Partnership. The General Partner will be responsible for managing all of the Partnership’s businesses and operations. Enterprise Products OLP is a wholly owned subsidiary of Enterprise Products Partners L.P. The Partnership, the General Partner, Enterprise Products OLP and Enterprise Products Partners are affiliates under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO, Inc. (“EPCO”) and it’s affiliates.

F-47

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

acquire a 66% interest in the following companies, all of which are indirect wholly-owned subsidiaries of Enterprise Products Partners:


	•	Mont Belvieu Caverns;

	•	Acadian Gas;

	•	Lou-Tex Propylene;

	•	Sabine Propylene; and

	•	South Texas NGL in 2007.

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.

The unaudited condensed combined results of operations of the Company for the three and six months ended June 30, 2006 are not necessarily indicative of results expected for the full year.

We have not included earnings per unit data since we do not have any outstanding units.


2.	General Accounting Policies and Related Matters

Cumulative effect of change in accounting principle

Certain key employees of EPCO who allocate a portion of their time to our affairs participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of restricted units of Enterprise Products Partners and limited partner interests in EPE Unit L.P. Prior to January 1, 2006, EPCO accounted for these awards using the provisions of Accounting Principles Board Opinion 25, “Accounting for Stock Issued to Employees.” On January 1, 2006, EPCO adopted SFAS 123(R), “Accounting for Stock-Based Compensation,” to account for such awards. Upon adoption of this accounting standard, we recognized a cumulative effect of change in accounting principle of $9 thousand (a benefit). Such awards are immaterial to our combined financial position, results of operations and cash flows.

Estimates

Preparing our combined financial statements in conformity with accounting principles generally accepted in the United States of America (generally referred to as “GAAP”) requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during a given period. Our actual results could differ from these estimates.

Inventories

Our inventory consists of natural gas volumes valued at the lower of average cost or market, with “market” determined by industry posted prices. At June 30, 2006 and December 31, 2005, the value of our natural gas inventory was $13.6 million and $9.9 million, respectively. As a result of fluctuating market conditions, we recognize lower of average cost or market (“LCM”) adjustments when the historical cost of our

F-48

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

inventory exceeds its net realizable value. These non-cash adjustments are recorded as a component of operating costs and expenses. No LCM adjustments were required during the first six months of 2006 and 2005.

In March 2006, our inventory was segregated to include natural gas volumes dedicated to the fulfillment of forward-sales contracts. The forward-sale inventory was $13.4 million at June 30, 2006.

Provision for income taxes

In May 2006, the State of Texas substantially revised its existing state franchise tax. The revised tax (the “Texas Margin Tax”) becomes effective for franchise tax reports due on or after January 1, 2008. In general, legal entities that conduct business in Texas and benefit from limited liability protection are subject to the Texas Margin Tax. As a result of the change in tax law, management believes that our tax status in the State of Texas will change such that we will become subject to the Texas Margin Tax. We recorded an estimated deferred tax liability of $21 thousand for the Texas Margin Tax in June 2006.

Storage well gains and losses

Storage well gains and losses occur when product movements into a storage well are different than those redelivered to customers. In general, such variations result from difficulties in precisely measuring significant volumes of liquids at varying flow rates and temperatures. It is expected that substantially all product delivered into a storage well will be withdrawn over time. A measurement loss in one period is expected to be offset by a measurement gain in a subsequent period, unless product is physically lost in a storage well due to problems with cavern integrity.

At June 30, 2006 and December 31, 2005, our storage imbalance account was $0.8 million and $4.5 million. Net measurement losses of $3.7 million were charged to the reserve during the six months ended June 30, 2006.

F-49

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

3. Property, Plant and Equipment

Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:


	June 30,		December 31,
	2006		2005

Natural gas and petrochemical pipelines and related equipment(1)	$	344,802	$	343,843
Underground storage wells and related assets(2)		277,095		260,976
Transportation equipment(3)		1,023		1,102
Land		14,743		14,743
Construction in progress		35,679		15,063

Total		673,342		635,727
Less accumulated depreciation		133,413		123,530

Property, plant and equipment, net	$	539,929	$	512,197


(1)		Includes natural gas and petrochemical pipelines, office furniture and equipment, buildings and related assets.

(2)		Underground and other storage facilities include underground product storage caverns and related integral specific assets such as pipes and compressors.

(3)		Transportation equipment includes vehicles and similar assets used in our various operations.

Depreciation expense for the three months ended June 30, 2006 and 2005 was $5.0 million and $4.6 million, respectively. We recorded $10.0 million and $9.3 million of depreciation expense for the six months ended June 30, 2006 and 2005, respectively.


4.	Investments in and Advances to Unconsolidated Affiliate — Evangeline

Acadian Gas, through a wholly owned subsidiary, owns a collective 49.51% equity interest in Evangeline which consists of a 45% direct ownership interest in Evangeline Gas Pipeline, L.P. (“EGP”) and a 45.05% direct interest in Evangeline Gas Corp. (“EGC”). EGC also owns a 10% direct interest in EGP. Third parties own the remaining equity interests in EGP and EGC. Acadian Gas does not have a controlling interest in the Evangeline entities, but does exercise significant influence on Evangeline’s operating policies. Acadian Gas accounts its financial investment in Evangeline using the equity method since it is not the primary beneficiary of a variable interest. Our investment in Evangeline is classified within our Natural Gas Pipelines & Services business segment.

At June 30, 2006 and December 31, 2005, the carrying value of our investment in Evangeline was $2.8 million and $2.4 million, respectively. Our Unaudited Condensed Combined Statements of Operations reflect equity earnings from Evangeline of $0.2 million and $0.1 million for the three months ended June 30, 2006 and 2005, respectively. We recorded $0.4 million and $0.2 million of equity earnings from Evangeline for the six months ended June 30, 2006 and 2005, respectively.

F-50

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

The following table presents unaudited income statement data for Evangeline for the periods indicated (on a 100% basis):


	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005

Revenues	$	75,581	$	76,387	$	156,123	$	131,806
Operating income		1,970		1,861		3,911		3,637
Net income		404		189		718		264


5.	Intangible Assets

At June 30, 2006 and December 31, 2005, our intangible assets consisted primarily of renewable storage contracts with various customers that we acquired in connection with the purchase of storage caverns from a third party in January 2002. At June 30, 2006 and December 31, 2005, the carrying values of these intangible assets were $7.1 million and $7.2 million, respectively. We recorded $0.2 million and $0.1 million in amortization expense associated with these intangible assets for the year ended December 31, 2005 and the six months ended June 30, 2006, respectively. For the remainder of 2006, amortization expense associated with these intangible assets is currently estimated at $0.1 million.


6.	Related Party Transactions

The following table summarizes our combined 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
Enterprise Products Partners	$	30,546	$	20,334	$	55,911	$	42,736
Evangeline		73,161		74,140		151,380		127,398

Total	$	103,707	$	94,474	$	207,291	$	170,134

Operating costs and expenses
EPCO	$	7,755	$	9,287	$	16,613	$	16,403
Enterprise Products Partners		3,700		3,641		8,037		4,737

Total	$	11,455	$	12,928	$	24,650	$	21,140

General and administrative costs
EPCO	$	950	$	904	$	1,703	$	1,920

Relationship with Enterprise Products Partners

Enterprise Products Partners was the shipper of record on our Sabine Propylene and Lou-Tex Propylene pipelines. For the three months ended June 30, 2006 and 2005, we recorded $9.9 million and $9.6 million, respectively, of related party transportation revenues from Enterprise Products Partners with respect to these pipelines. We recorded $18.3 million and $19.1 million of such related party revenues during the six months ended June 30, 2006 and 2005, respectively.

Prior to 2004, Sabine Propylene was regulated by the Federal Energy Regulatory Commission (“FERC”). Our Lou-Tex Propylene pipeline was also subject to the FERC’s jurisdiction until 2005. For the periods in which Sabine Propylene and Lou-Tex Propylene were subject to FERC regulations, related party revenues with

F-51

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

Enterprise Products Partners were based on the maximum tariff rate allowed for each system. We continued to charge Enterprise Products Partners such maximum transportation rates after both entities were declared exempt from FERC oversight.

Enterprise Products Partners has entered into exchange agreements with third parties involving use of the Sabine Propylene and Lou-Tex Propylene pipelines. Enterprise Products Partners recorded $4.3 million and $3.8 million in revenues during the three months ended June 30, 2006 and 2005, respectively, in connection with such agreements. Enterprise Products Partners recorded $7.5 million and $8.5 million of such revenues during the six months ended June 30, 2006 and 2005, respectively. Apart from such agreements, Enterprise Products Partners did not utilize the Sabine Propylene and Lou-Tex Propylene assets. Enterprise Products Partners has assigned certain agreements with third parties involving the use of our Sabine Propylene and Lou-Tex Propylene pipelines to us but remains jointly and severally liable on those agreements.

Our related party revenues from Enterprise Products Partners also include the sale of natural gas. Our natural gas sales to Enterprise Products Partners were $16.4 million and $6.8 million during the three months ended June 30, 2006 and 2005, respectively. We recorded $28.9 million and $15.7 million of such revenues during the six months ended June 30, 2006 and 2005, respectively.

Our related party operating costs and expenses include the cost of natural gas Enterprise Products Partners sold to us. Such amounts were $3.7 million and $3.6 million for the three months ended June 30, 2006 and 2005, respectively. We recorded $8.0 million and $4.7 million of such expenses during the six months ended June 30, 2006 and 2005, respectively. In addition, Enterprise Products Partners has furnished letters of credit on behalf of Evangeline’s debt service requirements. At December 31, 2005, such outstanding letters of credit totaled $1.2 million.

We also provide underground storage services to Enterprise Products Partners for the storage of NGLs and petrochemicals. We recorded $4.3 and $3.9 for the three months ended June 30, 2006 and 2005, and $8.7 and $8.0 for the six month ended June 30, 2006 and 2005, respectively, in storage revenue from Enterprise Products Partners.

We expect that certain commercial arrangements with Enterprise Products Partners will change once the Partnership completes its initial public offering. These changes will include: (i) a reduction in transportation rates previously charged by us to Enterprise Products Partners for usage of the Lou-Tex Propylene and Sabine Propylene pipelines following the assignment to us of the related exchange agreements by Enterprise Products Partners; (ii) an increase in storage fees charged Enterprise Products Partners by Mont Belvieu Caverns related to the storage activities of Enterprise Products Partners’ octane enhancement, isomerization and NGL and petrochemical marketing businesses; and (iii) the allocation of measurement gains and losses associated with products delivered to us by Enterprise Products Partners. In addition, in connection with the equity investments retained by Enterprise Products Partners, we expect that the Mont Belvieu Caverns limited liability company agreement will provide for the special allocation to Enterprise Products Partners of an amount equal to the subsidiary’s net measurement gain or loss each period.

The Company has operated within the Enterprise Product Partners cash management program for all periods presented. For purposes of presentation in the Statements of Combined Cash Flows, cash flows from financing activities represent transfers of excess cash from the Company to Enterprise Products Partners and shortfall contributions from Enterprise Products Partners to the Company are equal to cash provided by operations less cash used in investing activities. Such transfers of excess and shortfalls of cash are shown as distributions to or contributions from owners in the Statements of Combined Owners’ Net Investment. As a result, the combined financial statements do not present cash balances for any of the periods presented.

F-52

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

Relationship with EPCO

We have no employees. All of our operating functions are performed by employees of EPCO pursuant to an administrative services agreement. EPCO also provides general and administrative support services to Acadian Gas, Sabine Propylene and Lou-Tex Propylene in accordance with the administrative services agreement. We, Enterprise Products Partners and the other affiliates of EPCO are parties to the administrative services agreement. The significant terms of the administrative services agreement are as follows:


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

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

	•	EPCO allows us to participate as named insureds in its overall insurance program with the associated premiums and related costs being allocated to us. We reimbursed EPCO $0.5 million and $0.6 million for insurance costs during the three months ended June 30, 2006 and 2005, respectively. Such reimbursements were $0.8 million and $1.2 million for the six months ended June 30, 2006 and 2005, respectively.

Our operating costs and expenses for the six month ended June 30, 2006 and 2005 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Our reimbursements to EPCO for operating costs and expenses were $7.8 million and $9.3 million during the three months ended June 30, 2006 and 2005, respectively. Such reimbursements were $16.6 million and $16.4 million for the six months ended June 30, 2006 and 2005, respectively.

Likewise, our general and administrative costs include amounts we reimburse to EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to administrative services agreement based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). Our reimbursements to EPCO for general and administrative costs were $1.0 million and $0.9 million during the three months ended June 30, 2006 and 2005, respectively. Such reimbursements were $1.7 million and $1.9 million during the six months ended June 30, 2006 and 2005, respectively.

A small number of key employees who devote a portion of their time to the Company’s operations and affairs participate in long-term incentive compensation plans managed by EPCO. These plans include the issuance of restricted units of Enterprise Products Partners and limited partner interests in EPE Unit L.P. The amount of equity-based compensation allocable to the Company’s businesses was $29 thousand for the six months ended June 30, 2006. Such amounts are immaterial to our combined financial position, results of operations and cash flows.

Relationships with Evangeline

We sell natural gas to Evangeline, which, in turn, uses such natural gas to satisfy its sales commitments to Entergy. Our sales of natural gas to Evangeline totaled $73.2 million and $74.1 million during the three

F-53

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

months ended June 30, 2006 and 2005, respectively. We recorded $151.4 million and $127.4 million of natural gas sales to Evangeline during the six months ended June 30, 2006 and 2005, respectively.

Additionally, we have a service agreement with Evangeline whereby we provide Evangeline with construction, operations, maintenance and administrative support related to its pipeline system. Evangeline paid us $0.2 million and $0.1 million for such services during the three months ended June 30, 2006 and 2005, respectively. We received $0.3 million and $0.2 million for these services during the six months ended June 30, 2006 and 2005, respectively.


7.	Business Segments

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 include equity earnings from Evangeline in our measurement of segment gross operating margin and operating income. Our equity investments in midstream energy operations such as those conducted by Evangeline are a vital component of our long-term business strategy and important to the operations of Acadian Gas. This method of operation enables us to achieve favorable economies of scale relative to our level of investment and also lowers our exposure to business risk compared the profile we would have on a stand-alone basis. Our equity investments are within the same industry as our combined operations, thus we believe treatment of earnings from our equity method investee as a component of gross operating margin and operating income is appropriate.

F-54

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

construction-in-progress. Segment assets represent the net carrying value of assets that contribute to the gross operating margin of a particular segment. Since assets under construction generally do not contribute to segment gross operating margin until completed, such assets are excluded from segment asset totals until they are deemed operational.

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)	$	220,728		$	214,853		$	503,791		$	400,029
Less: Operating costs and expenses(1)		(208,243	)		(203,449	)		(478,586	)		(377,779	)
Add: Equity in income of unconsolidated affiliate(1)		200			144			354			197
Depreciation, amortization and accretion in operating costs and expenses(2)		5,108			4,748			10,149			9,432
Loss on sale of assets in operating costs and expenses(2)		(6	)		(1	)		(13	)		(1	)

Total segment gross operating margin	$	17,787		$	16,295		$	35,695		$	31,878


(1)		These amounts are taken from our Unaudited Condensed Statements of Combined Operations and Comprehensive Income.

(2)		These non-cash expenses are taken from the operating activities section of our Unaudited Condensed Statements of Combined Cash Flows.

A reconciliation of total segment gross operating margin to operating income and income before provision for income taxes and the cumulative effect of a 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	$	17,787		$	16,295		$	35,695		$	31,878
Adjustments to reconcile total segment gross operating margin to operating income:
Depreciation, amortization and accretion in operating costs and expenses		(5,108	)		(4,748	)		(10,149	)		(9,432	)
Gain on sale of assets in operating costs and expenses		6			1			13			1
General and administrative costs		(959	)		(1,141	)		(1,735	)		(2,436	)

Combined operating income		11,726			10,407			23,824			20,011
Other (income) expense, net								4

Income before provision for income taxes and cumulative effect of change in accounting principle	$	11,726		$	10,407		$	23,828		$	20,011

F-55

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

Information by segment, together with reconciliations to the combined total revenues and expenses, is presented in the following tables:


	NGL &
	Petrochemical		Natural Gas		Petrochemical		Construction-
	Storage		Pipelines		Pipeline		in-		Combined
	Services		& Services		Services		Progress		Totals

Revenues from third parties:
Three months ended June 30, 2006	$	9,740	$	107,281					$	117,021
Three months ended June 30, 2005		8,282		112,097						120,379
Six months ended June 30, 2006		19,118		277,382						296,500
Six months ended June 30, 2005		15,067		214,828						229,895
Revenues from related parties:
Three months ended June 30, 2006		4,257		89,599	$	9,851				103,707
Three months ended June 30, 2005		3,950		80,966		9,558				94,474
Six months ended June 30, 2006		8,723		180,252		18,316				207,291
Six months ended June 30, 2005		7,963		143,098		19,073				170,134
Total revenues:
Three months ended June 30, 2006		13,997		196,880		9,851				220,728
Three months ended June 30, 2005		12,232		193,063		9,558				214,853
Six months ended June 30, 2006		27,841		457,634		18,316				503,791
Six months ended June 30, 2005		23,030		357,926		19,073				400,029
Equity in income of unconsolidated affiliate:
Three months ended June 30, 2006				200						200
Three months ended June 30, 2005				144						144
Six months ended June 30, 2006				354						354
Six months ended June 30, 2005				197						197
Gross operating margin by individual business segment and in total:
Three months ended June 30, 2006		5,084		3,954		8,749				17,787
Three months ended June 30, 2005		2,621		5,131		8,543				16,295
Six months ended June 30, 2006		8,871		10,881		15,943				35,695
Six months ended June 30, 2005		5,705		9,116		17,057				31,878
Segment assets — property, plant and equipment:
At June 30, 2006		203,187		207,444		93,619	$	35,679		539,929
At December 31, 2005		191,757		211,045		94,332		15,063		512,197
Investments in and advances to unconsolidated affiliate (see Note 4):
At June 30, 2006				2,788						2,788
At December 31, 2005				2,375						2,375

F-56

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

The following table provides additional information regarding our combined revenues and costs and expenses for the periods indicated:


	For the Three Months				For the Six Months
	Ended June 30,				Ended June 30,
	2006		2005		2006		2005

Combined revenues
Sales of natural gas	$	194,507	$	190,850	$	452,694	$	353,553
Transportation — natural gas		2,373		2,214		4,940		4,373
Transportation — petrochemicals		9,851		9,558		18,316		19,073
Storage		13,997		12,231		27,841		23,030

Total	$	220,728	$	214,853	$	503,791	$	400,029

Combined cost and expenses
Cost of natural gas sales	$	189,258	$	184,388	$	442,101	$	342,193
Operating expenses		13,871		14,312		26,323		26,153
Depreciation, amortization, and accretion		5,108		4,748		10,149		9,432
Gain/losses on sale of assets		6		1		13		1
General and administrative costs		959		1,141		1,735		2,436

Total	$	209,202	$	204,590	$	480,321	$	380,215

Revenues from the purchase and resale of natural gas included in Natural Gas Pipelines & Services segment, accounted for 88% and 89% of total combined revenues for the three months ended June 30, 2006 and 2005, and 90% and 88% for the six months ended June 30, 2006 and 2005, respectively. The cost of natural gas sales accounted for 91% of total combined operating costs and expenses for each of the three months ended June 30, 2006 and 2005, and 92% and 91% for the six months ended June 30, 2006 and 2005, respectively.

Revenues from Enterprise Products Partners accounted for 14% and 9% of total combined revenues for the three months ended June 30, 2006 and 2005, and 11% for each of the six months ended June 30, 2006 and 2005. Enterprise Products Partners accounted for 100% of the revenues recorded by our Petrochemical Pipeline Services segment. Storage revenues from Enterprise Products Partners accounted for 30% and 32% of NGL & Petrochemical Storage Services segment for the three months ended June 30, 2006 and 2005, and 31% and 35% for the six months ended June 30, 2006 and 2005, respectively.

Revenues from Evangeline, our unconsolidated affiliate (see Note 4), accounted for 33% and 35% of total combined revenues for the three months ended June 30, 2006 and 2005, and 30% and 32% for the six months ended June 30, 2006 and 2005, respectively. See Note 6 for information regarding our related party transactions.


8.	Financial Instruments

F-57

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

The general partner of Enterprise Products Partners monitored the hedging strategies associated with the physical and financial risks of Acadian Gas (such as those mentioned previously), approved specific activities subject to the policy (including authorized products, instruments and markets) and established specific guidelines and procedures for implementing and ensuring compliance with the policy. DEP Holdings, general partner of the Partnership, will continue such policies in the future.

Due to the limited number and nature of the financial instruments utilized by Acadian Gas, the effect on the portfolio of a hypothetical 10% movement in the underlying quoted market prices of natural gas is negligible at June 30, 2006 and December 31, 2005. The fair value of our commodity financial instrument was negligible at June 30, 2006 and a liability of $0.1 million at December 31, 2005. We recorded $0.3 million of expense related to our commodity financial instruments during the three and six months ended June 30, 2006. We recorded nominal amounts of expense related to this portfolio during the three and six months ended June 30, 2005.


9.	Commitments and Contingencies

Litigation

In 1997, Acadian Gas, along with numerous other energy companies, was named a defendant in actions brought by Jack Grynberg on behalf of the U.S. Government under the False Claims Act. Generally, these complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands. The complaint alleges that the U.S. Government was deprived of royalties as a result of this conspiracy. The plaintiff in this case seeks royalties that he contends the U.S. government should have received had heating value and volume been differently measured, analyzed, calculated and reported, together with interest, treble damages, civil penalties, expenses and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. These matters have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming, filed June 1997). On October 20, 2006 the U.S. District Court dismissed all of Grynberg’s claim with prejudice.

We are not aware of any other significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.

Redelivery Commitments

We transport and store natural gas volumes and store NGL and petrochemical products for third parties under various contracts. Under the terms of these agreements, we are generally required to redeliver volumes

F-58

DUNCAN ENERGY PARTNERS PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS — (Continued)

to the owner on demand. We are insured for any physical loss of such volumes resulting from catastrophic events. At June 30, 2006 and December 31, 2005, NGL and petrochemical products aggregating 10.1 MMBbls and 15.2 MMBbls, respectively, were due to be redelivered to their owners along with 681 billion British thermal units (“Bbtus”) and 730 Bbtus of natural gas, respectively.

Operating Leases

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

Acadian Gas leases an underground natural gas storage cavern that is integral to its operations. The primary use of this cavern is to store natural gas held-for-sale by Acadian Gas. The current term of the cavern lease expires in December 2012. The term of this contract does not provide for an additional renewal period, but it requires the lessor to enter into negotiations with us under similar terms and conditions if we wish to extend the lease agreement beyond December 2012.

In addition, our pipeline operations have entered into leases for land held pursuant to right-of-way agreements. Our significant right-of-way agreements have original terms that range from five to 50 years and include renewal options that could extend the agreements for up to an additional ten years. Our rental payments are generally at fixed rates, as specified in the individual contract, and may be subject to escalation provisions for inflation and other market-determined factors.

Lease and rental expense included in operating income was $0.4 million and $0.3 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 $0.8 million and $0.6 million, respectively.

* * * *

F-59

DUNCAN ENERGY PARTNERS L.P.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Duncan Energy Partners L.P.

We have audited the accompanying balance sheet of Duncan Energy Partners L.P. (the “Partnership”) as of September 30, 2006. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of the Partnership at September 30, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

November 1, 2006

F-60

DUNCAN ENERGY PARTNERS L.P.

BALANCE SHEET

AT SEPTEMBER 30, 2006


ASSETS
Deferred offering costs	$	1,361,156

Total assets	$	1,361,156


LIABILITIES AND PARTNERS’ EQUITY
Accounts payable	$	522,232
Accounts payable — related party		838,924
Partners’ equity:
Limited partner		2,940
General partner		60
Receivable from partners		(3,000	)

Total liabilities and partners’ equity	$	1,361,156

See Note to Balance Sheet

F-61

DUNCAN ENERGY PARTNERS L.P.

NOTE TO BALANCE SHEET

Nature of operations

Duncan Energy Partners L.P. (the “Partnership”) was formed on September 29, 2006 as a Delaware limited partnership to acquire ownership interests in midstream energy businesses from subsidiaries of Enterprise Products Partners L.P. These ownership interests will be acquired by the Partnership in connection with its anticipated initial public offering to be completed in the first quarter of 2007.

The business of the Partnership will initially consist of (i) receiving, storing and delivering natural gas liquids (“NGLs) and petrochemical products, (ii) gathering, transporting, storing and marketing natural gas and (iii) transporting NGLs and propylene. The Partnership will acquire a 66% interest in the following companies, all of which are wholly-owned subsidiaries of Enterprise Products Partners L.P. at September 30, 2006:


	•	Mont Belvieu Caverns, L.P. (“Mont Belvieu Caverns”), which receives, stores and delivers NGLs and petrochemical products for industrial customers located along the upper Texas Gulf Coast;

	•	Acadian Gas, LLC (“Acadian Gas”), which gathers, transports, stores and markets natural gas in Louisiana utilizing over 1,000 miles of natural gas transmission and gathering pipelines and a leased storage cavern;

	•	Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), which transports chemical-grade propylene between Sorrento, Louisiana and Mont Belvieu, Texas;

	•	Sabine Propylene Pipeline L.P. (“Sabine Propylene”), which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana; and

	•	South Texas NGL Pipelines, LLC (“South Texas NGL”), which will transport NGLs from Corpus Christi, Texas to Mont Belvieu, Texas. A 223-mile pipeline that will form the largest part of a pipeline system was purchased by Enterprise Products Partners in August 2006, and the Partnership is constructing and acquiring additional pipeline assets to enable it to transport NGL products beginning in January 2007. Additional expansions to this system are scheduled to be completed during 2007.

Enterprise Products Partners L.P. will control of the Partnership’s 2% general partner, DEP Holdings, LLC (the “General Partner”), which will direct the operations of the Partnership. Enterprise Products Operating L.P. (a wholly owned subsidiary of Enterprise Products Partners L.P.) is the organizational limited partner of the Partnership. The Partnership, the General Partner, Enterprise Products Operating L.P. and Enterprise Products Partners L.P. are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO, Inc.

Deferred offering costs

Direct offering costs representing specific legal, accounting, and other third party services incurred to date in connection with the anticipated initial public offering of the Partnership will be deferred and charged against the gross proceeds of the offering. Offering costs paid by related parties prior to the offering will be reimbursed from the proceeds of the offering. At this time there are no other obligations for organizational costs intended to be reimbursed to related parties.

Receivable from partners

The General Partner and Enterprise Products Operating L.P. made their initial cash capital contributions of $60 and $2,940, respectively, subsequent to September 30, 2006.

* * * *

F-62

DEP HOLDINGS, LLC

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Owner of DEP Holdings, LLC

We have audited the accompanying balance sheet of DEP Holdings, LLC (the “General Partner”) as of October 31, 2006. This financial statement is the responsibility of the General Partner’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. The General Partner is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the General Partner’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of the General Partner at October 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

November 1, 2006

F-63

DEP HOLDINGS, LLC

BALANCE SHEET

AT OCTOBER 31, 2006


ASSETS
Cash	$	940
Investment in Duncan Energy Partners L.P.		60

Total Assets	$	1,000


MEMBER’S EQUITY
Member’s Equity	$	1,000

See Note to Balance Sheet

F-64

DEP HOLDINGS, LLC

NOTE TO BALANCE SHEET

Nature of Operations

DEP Holdings, LLC ( the “General Partner”) is a Delaware limited liability company that was formed on September 29, 2006, to own a 2% general partner interest in Duncan Energy Partners L.P. (the “Partnership”), a Delaware limited partnership. The General Partner is wholly owned by Enterprise Products Operating L.P., a wholly owned subsidiary of Enterprise Products Partners L.P.

On October 20, 2006, Enterprise Products Operating L.P. contributed $1,000 to the General Partner, which used $60 of such funds to acquire a general partner interest in the Partnership. The Partnership was formed on September 29, 2006 and its initial purpose is to acquire ownership interests in midstream energy businesses of Enterprise Products Partners L.P. Such ownership interests will be acquired by the Partnership in connection with an anticipated initial public offering by the Partnership. The Partnership, the General Partner, Enterprise Products Operating L.P. and Enterprise Products Partners L.P. are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO, Inc.

* * * *

F-65

APPENDIX A — AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

A-1

APPENDIX B — GLOSSARY OF TERMS

Acadian Gas: Acadian Gas, LLC, a Delaware limited liability company.

available cash: Available cash is defined in our partnership agreement and means, with respect to any fiscal quarter ending prior to liquidation:


	•	the sum of:


	•	all cash and cash equivalents of Duncan Energy Partners and its subsidiaries on hand at the end of that quarter; and

	•	all additional cash and cash equivalents of Duncan Energy Partners and its subsidiaries on hand immediately prior to the date of determination of available cash with respect to the fiscal quarter;


	•	less the amount of cash reserves determined by our general partner to be necessary or appropriate to:


	•	provide for the proper conduct of our business (including reserves for future capital expenditures and for our future credit needs);

	•	comply with applicable law or any debt instrument or other agreement; or

	•	provide funds for distributions to unitholders and our general partner in respect of any one or more of the next four quarters.

basis differential: The cost of transporting natural gas from Henry Hub to the destination point.

Bcf: One billion cubic feet of natural gas.

Bcf/d: One billion cubic feet of natural gas per day.

Bbls: Barrels.

Btu: British thermal units.

Bbtu/d: One billion Btus per day.

capital account: The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a general partner interest, a common unit or any other partnership interest will be the amount which that capital account would be if that common unit or other partnership interest were the only interest in Duncan Energy Partners L.P. held by a partner.

closing price: The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the New York Stock Exchange or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by the our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors.

common units: Represent limited partner interests that entitle the holders to participate in our cash distributions and to exercise the rights and privileges available to limited partners under our partnership agreement.

condensate: Similar to crude oil and produced in association with natural gas gathering and processing.

current market price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

B-1

DEP Holdings: DEP Holdings, LLC.

Enterprise GP Holdings: Enterprise GP Holdings L.P., a publicly traded partnership that owns the general partner of Enterprise Products Partners.

Enterprise Products Partners: Enterprise Products Partners L.P. and its consolidated subsidiaries.

Enterprise Products OLP: Enterprise Products Operating L.P., the operating partnership of Enterprise Products Partners.

Enterprise Products GP: Enterprise Products GP, LLC, the general partner of Enterprise Products Partners.

EPE Holdings: EPE Holdings, LLC, the general partner of Enterprise GP Holdings.

EPCO: EPCO, Inc., an affiliate of our ultimate parent company, and its affiliates, unless the context indicates otherwise.

Evangeline: Our equity method investment in Evangeline Gas Pipeline L.P. and Evangeline Gas Corp. For information regarding this unconsolidated affiliate, please read Note 4 of the Notes to Combined Financial Statements of Duncan Energy Partners Predecessor.

feedstock: A raw material required for an industrial process such as in petrochemical manufacturing.

FERC: Federal Energy Regulatory Commission

fractionation: The process of separating or refining NGLs into their component products by a process known as fractional distillation.

fractionator: A processing unit that separates a mixed stream of NGLs into component products by fractionation.

GAAP: Accounting principles generally accepted in the United States of America.

LCM: Lower of average cost or market.

Lou-Tex Propylene: Lou-Tex Propylene Pipeline, L.P., a Texas limited partnership.

MBbls/d: One thousand barrels per day.

MBPD: Thousand barrels per day.

MMBbls: One million barrels.

MMBtu: One million British thermal units.

MMBtu/d: One million British thermal units per day.

MMcf: One million cubic feet of natural gas.

MMcf/d: One million cubic feet per day.

Mont Belvieu Caverns: Mont Belvieu Caverns, L.P., a Delaware limited partnership, or its successor Mont Belvieu Caverns, LLC.

NGLs: Natural gas liquids which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline. NGLs are used by the petrochemical or refining industries to produce plastics, motor gasoline and other industrial and consumer products and also are used as residential, agricultural and industrial fuels.

operating expenditures: All of our cash expenditures and cash expenditures of our subsidiaries, including, without limitation, taxes, reimbursements of our general partner, repayment of working capital borrowings, interest payments and sustaining capital expenditures, subject to the following:

(a) Payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings, will not constitute operating expenditures.

B-2

(b) Operating expenditures will not include:

(1) capital expenditures made for acquisitions or for capital improvements;

(2) payment of transaction expenses relating to interim capital transactions; or

(3) distributions to unitholders.

Where capital expenditures are made in part for acquisitions or for capital improvements and in part for other purposes, our general partner, with the concurrence of the conflicts committee, shall determine the allocation between the amounts paid for each and, with respect to the part of such capital expenditures made for other purposes, the period over which the capital expenditures made for other purposes will be deducted as an operating expenditure in calculating operating surplus.

Operating Partnership: DEP Operating Partnership, L.P., a Delaware limited partnership.

Operating Partnership Agreement: The Agreement of Limited Partnership of the Operating Partnership dated as of September 29, 2006, as amended from time to time.

Our general partner: DEP Holdings, LLC.

propylene: A type of liquid hydrocarbon derived from oil or natural gas that is used to make polypropylene. Refinery-grade propylene (a mixture of propane and propylene) is separated into either polymer-grade propylene or chemical-grade propylene along with by-products of propane and mixed butane. Polymer-grade propylene can also be produced from chemical-grade propylene feedstock.

Sabine Propylene: Sabine Propylene Pipeline, L.P., a Texas limited partnership.

South Texas NGL: South Texas NGL Pipelines, LLC, a Delaware limited liability company.

TEPPCO Partners: TEPPCO Partners, L.P., a publicly traded partnership, and its subsidiaries.

TEPPCO GP: Texas Eastern Products Pipeline Company, LLC, the general partner of TEPPCO Partners.

throughput: The volume of natural gas or NGLs transported or passing through a pipeline, plant, terminal or other facility in an economically meaningful period of time.

B-3

13,000,000 Common Units

Representing Limited Partner Interests

PROSPECTUS

, 2007

Lehman Brothers

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution.*

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee and the NYSE filing fee, the amounts set forth below are estimates.


SEC registration fee	$	33,593
NASD filing fee		31,895
NYSE listing fee		*
Printing and engraving expenses		*
Fees and expenses of legal counsel		*
Accounting fees and expenses		*
Structuring fees		*
Transfer agent and registrar fees		*
Miscellaneous		*

Total	$	*


*		To be provided by amendment.


Item 14.	*Indemnification of Directors and Officers.*

The section of the prospectus entitled “Description of Material Provisions of Our Partnership Agreement — Indemnification” is incorporated herein by this reference. Reference is also made to the Underwriting Agreement filed as Exhibit 1.1 to this registration statement. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.

Section 18-108 of the Delaware Limited Liability Company Act provides that, subject to such standards and restrictions, if any, as are set forth in its limited liability company agreement, a Delaware limited liability company may, and shall have the power to, indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. The limited liability company agreement of DEP Holdings, LLC provides for the indemnification of (i) present or former members of the Board of Directors of DEP Holdings, LLC or any committee thereof, (ii) present or former officers, employees, partners, agents or trustees of DEP Holdings, LLC or (iii) persons serving at the request of DEP Holdings, LLC in another entity in a similar capacity as that referred to in the immediately preceding clauses (i) or (ii) (each, a “General Partner Indemnitee”) to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including reasonable legal fees and expenses), judgments, fines, penalties, interest, settlements and other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any such person may be involved, or is threatened to be involved, as a party or otherwise, by reason of such person’s status as a General Partner Indemnitee; provided, that in each case the General Partner Indemnitee acted in good faith and in a manner which such General Partner Indemnitee believed to be in, or not opposed to, the best interests of DEP Holdings, LLC and, with respect to any criminal proceeding, had no reasonable cause to believe such General Partner Indemnitee’s conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendre, or its equivalent, shall not create a presumption that the General Partner Indemnitee acted in a manner contrary to that specified above. Any indemnification pursuant to these provisions shall be made only out of the assets of DEP Holdings, LLC. DEP

II-1

Holdings, LLC is authorized to purchase and maintain insurance, on behalf of the members of its Board of Directors, its officers and such other persons as the Board of Directors may determine, against any liability that may be asserted against or expense that may be incurred by such person in connection with the activities of DEP Holdings, LLC, regardless of whether DEP Holdings, LLC would have the power to indemnify such person against such liability under the provisions of its limited liability company agreement.


Item 15.	*Recent Sales of Unregistered Securities.*

On September 29, 2006, in connection with the formation of the partnership, Duncan Energy Partners L.P. issued (1) to DEP Holdings, LLC, the 2% general partner interest in the partnership for $60 and (2) to Enterprise Products Operating L.P., the 98% limited partner interest in the partnership for $2,940, in an offering exempt from registration under Section 4(2) of the Securities Act of 1933. There have been no other sales of unregistered securities within the past three years.


Item 16.	*Exhibits.*

The following documents are filed as exhibits to this registration statement:


Exhibit
Number				Description

	1	.1*	—	Form of Underwriting Agreement
	3	.1	—	Certificate of Limited Partnership of Duncan Energy Partners L.P.
	3	.2*	—	Form of Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P. (included as Appendix A)
	3	.3	—	Certificate of Formation of DEP Holdings, LLC
	3	.4*	—	Form of Amended and Restated Limited Liability Company Agreement of DEP Holdings, LLC
	3	.5	—	Certificate of Formation of DEP OLPGP, LLC
	3	.6*	—	Limited Liability Company Agreement of DEP OLPGP, LLC
	3	.7	—	Certificate of Limited Partnership of DEP Operating Partnership, L.P.
	3	.8*	—	Form of Amended and Restated Agreement of Limited Partnership of DEP Operating Partnership, L.P.
	4	.1*	—	Specimen certificate representing common units
	5	.1*	—	Opinion of Andrews Kurth LLP as to the legality of the securities being registered
	8	.1*	—	Opinion of Andrews Kurth LLP relating to tax matters
	10	.1*	—	Form of Contribution, Conveyance and Assumption Agreement
	10	.2*	—	Storage Lease (Enterprise Products NGL Marketing), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.3*	—	Storage Lease (Texas OLP), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.4*	—	Storage Lease (TE Products Pipeline Company), dated as of , 2007 between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.5*	—	Storage Lease (Belvieu Environmental Fuels), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.6*	—	Storage Lease (Butane Isomer), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.7*	—	Storage Lease (Enterprise Fractionation Plant), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.8*	—	Contribution, Conveyance and Assumption Agreement, dated as of , 2007, between Enterprise Products OLP and Mont Belvieu Caverns, LLC
	10	.9*	—	Contribution, Conveyance and Assumption Agreement, dated as of , 2007, between Enterprise Products OLP and South Texas NGL

II-2


Exhibit
Number				Description

	10	.10*	—	Pipeline Purchase and Sale Agreement, dated as of , 2007, between South Texas NGL and TEPPCO Crude Pipeline, L.P.
	10	.11*	—	Interconnection Lease Agreement, dated as of , 2007, between South Texas NGL and TE Products Pipeline Company
	10	.12*	—	Form of Amended and Restated Limited Liability Company Agreement of Mont Belvieu Caverns, LLC
	10	.13*	—	Form of Amended and Restated Limited Liability Company Agreement of Acadian Gas, LLC
	10	.14*	—	Form of Amended and Restated Limited Liability Company Agreement of South Texas NGL Pipelines, LLC
	10	.15*	—	Form of Amended and Restated Agreement of Limited Partnership of Enterprise Lou-Tex Propylene Pipeline, L.P.
	10	.16*	—	Form of Amended and Restated Agreement of Limited Partnership of Sabine Propylene Pipeline, L.P.
	10	.17*	—	Form of Fourth Amended and Restated Administrative Services Agreement
	10	.18*	—	Form of Omnibus Agreement
	10	.19*	—	Form of Credit Agreement
	21	.1*	—	List of Subsidiaries of Duncan Energy Partners L.P.
	23	.1	—	Consent of Deloitte & Touche LLP
	23	.2*	—	Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
	23	.3*	—	Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
	24	.1	—	Powers of Attorney (included on the signature page)


*		To be filed by amendment.


Item 17.	*Undertakings*

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction of the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act of 1933 shall be deemed to be part of this registration statement as of the time it was declared effective.

For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating

II-3

to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with DEP Holdings, LLC or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to DEP Holdings, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.

II-4

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on November 1, 2006.

DUNCAN ENERGY PARTNERS L.P.


	By:	DEP Holdings, LLC its General Partner


	By:	/s/ Richard H. Bachmann

Richard H. Bachmann

President and Chief Executive Officer

Each person whose signature appears below appoints Richard H. Bachmann and Michael A. Creel, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933 and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed below by the following persons in the capacities indicated on November 1, 2006.


Signature				Title

/s/ Dan L. Duncan Dan L. Duncan				Chairman of the Board and Director

/s/ Richard H. Bachmann Richard H. Bachmann				President, Chief Executive Officer and Director (Principal Executive Officer)

/s/ Michael A. Creel Michael A. Creel				Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)

/s/ Michael J. Knesek Michael J. Knesek				Senior Vice President, Controller and Principal Accounting Officer (Principal Accounting Officer)

/s/ Gil H. Radtke Gil H. Radtke				Senior Vice President, Chief Operating Officer and Director

/s/ W. Randall Fowler W. Randall Fowler				Senior Vice President, Treasurer and Director

II-5

EXHIBIT INDEX


Exhibit
Number				Description

	1	.1*	—	Form of Underwriting Agreement
	3	.1	—	Certificate of Limited Partnership of Duncan Energy Partners L.P.
	3	.2*	—	Form of Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P. (included as Appendix A)
	3	.3	—	Certificate of Formation of DEP Holdings, LLC
	3	.4*	—	Form of Amended and Restated Limited Liability Company Agreement of DEP Holdings, LLC
	3	.5	—	Certificate of Formation of DEP OLPGP, LLC
	3	.6*	—	Limited Liability Company Agreement of DEP OLPGP, LLC
	3	.7	—	Certificate of Limited Partnership of DEP Operating Partnership, L.P.
	3	.8*	—	Form of Amended and Restated Agreement of Limited Partnership of DEP Operating Partnership, L.P.
	4	.1*	—	Specimen certificate representing common units
	5	.1*	—	Opinion of Andrews Kurth LLP as to the legality of the securities being registered
	8	.1*	—	Opinion of Andrews Kurth LLP relating to tax matters
	10	.1*	—	Form of Contribution, Conveyance and Assumption Agreement
	10	.2*	—	Storage Lease (Enterprise Products NGL Marketing), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.3*	—	Storage Lease (Texas OLP), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.4*	—	Storage Lease (TE Products Pipeline Company), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.5*	—	Storage Lease (Belvieu Environmental Fuels), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.6*	—	Storage Lease (Butane Isomer), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.7*	—	Storage Lease (Enterprise Fractionation Plant), dated as of , 2007, between Enterprise Products Operating L.P. and Mont Belvieu Caverns, LLC
	10	.8*	—	Contribution, Conveyance and Assumption Agreement, dated as of , 2007, between Enterprise Products OLP and Mont Belvieu Caverns, LLC
	10	.9*	—	Contribution, Conveyance and Assumption Agreement, dated as of , 2007, between Enterprise Products OLP and South Texas NGL
	10	.10*	—	Pipeline Purchase and Sale Agreement, dated as of , 2007, between South Texas NGL and TEPPCO Crude Pipeline, L.P.
	10	.11*	—	Interconnection Lease Agreement, dated as of , 2007, between South Texas NGL and TE Products Pipeline Company
	10	.12*	—	Form of Amended and Restated Limited Liability Company Agreement of Mont Belvieu Caverns, LLC
	10	.13*	—	Form of Amended and Restated Limited Liability Company Agreement of Acadian Gas, LLC
	10	.14*	—	Form of Amended and Restated Limited Liability Company Agreement of South Texas NGL Pipelines, LLC
	10	.15*	—	Form of Amended and Restated Agreement of Limited Partnership of Enterprise Lou-Tex Propylene Pipeline, L.P.
	10	.16*	—	Form of Amended and Restated Agreement of Limited Partnership of Sabine Propylene Pipeline, L.P.
	10	.17*	—	Form of Fourth Amended and Restated Administrative Services Agreement
	10	.18*	—	Form of Omnibus Agreement
	10	.19*	—	Form of Credit Agreement
	21	.1*	—	List of Subsidiaries of Duncan Energy Partners L.P.

II-6


Exhibit
Number				Description

	23	.1	—	Consent of Deloitte & Touche LLP
	23	.2*	—	Consent of Andrews Kurth LLP (contained in Exhibit 5.1)
	23	.3*	—	Consent of Andrews Kurth LLP (contained in Exhibit 8.1)
	24	.1	—	Powers of Attorney (included on the signature page)


*		To be filed by amendment.

II-7

exv3w1

EXHIBIT 3.1

CERTIFICATE OF LIMITED PARTNERSHIP

DUNCAN ENERGY PARTNERS L.P.

This Certificate of Limited Partnership, dated September 28, 2006, has been duly executed and is filed pursuant to Section 17-201 of the Delaware Revised Uniform Limited Partnership Act (the “Act”) to form a limited partnership under the Act.

	1.		Name. The name of the limited partnership is “Duncan Energy Partners L.P.”

	2.		Registered Office; Registered Agent. The address of the registered office required to be maintained by Section 17-104 of the Act is:

Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801

The name and address of the registered agent for service of process required to be maintained by Section 17-104 of the Act are:

The Corporation Trust Company
Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801

General Partner. The name and the mailing address of the general partner is:

DEP Holdings, LLC
1100 Louisiana Street, 10th Floor
Houston, Texas 77002

IN WITNESS WHEREOF, the undersigned general partner has duly executed this Certificate of Limited Partnership as of the date first written above.


	DEP HOLDINGS, LLC
	By:	/s/ Richard H. Bachmann
		Richard H. Bachmann
		President and Chief Executive Officer

exv3w3

EXHIBIT 3.3

CERTIFICATE OF FORMATION

DEP HOLDINGS, LLC

This Certificate of Formation, dated September 28, 2006, has been duly executed and is filed pursuant to Section 18-201 of the Delaware Limited Liability Company Act (the “Act”) to form a limited liability company (the “Company”) under the Act.

	1.		Name. The name of the Company is “DEP Holdings, LLC”.

	2.		Registered Office; Registered Agent. The address of the registered office required to be maintained by Section 18-104 of the Act is:

Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801

The name and address of the registered agent for service of process required to be maintained by Section 18-104 of the Act are:

The Corporation Trust Company
Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801

Effective Time. The effective time of the formation of the Company contemplated hereby is immediately upon the filing of this Certificate of Formation with the Secretary of State of Delaware.

IN WITNESS WHEREOF, the undersigned has duly executed this Certificate of Formation as of the date first written above.



	/s/ Richard H. Bachmann
	Richard H. Bachmann, Authorized Person

exv3w5

Exhibit 3.5

CERTIFICATE OF FORMATION
OF
DEP OLPGP, LLC

	1.		Name. The name of the Company is “DEP OLPGP, LLC”.

	2.		Registered Office; Registered Agent. The address of the registered office required to be maintained by Section 18-104 of the Act is:

Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801

The name and address of the registered agent for service of process required to be
maintained by Section 18-104 of the Act are:

The Corporation Trust Company
Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801

Effective Time. The effective time of the formation of the Company contemplated hereby is immediately upon the filing of this Certificate of Formation with the Secretary of State of Delaware.

IN WITNESS WHEREOF, the undersigned has duly executed this Certificate of Formation as of the date first written above.



	/s/ Richard H. Bachmann
	Richard H. Bachmann, Authorized Person

exv3w7

Exhibit 3.7

CERTIFICATE OF LIMITED PARTNERSHIP

DEP OPERATING PARTNERSHIP, L.P.

Name. The name of the limited partnership is “DEP Operating Partnership, L.P.”

Registered Office; Registered Agent. The address of the registered office required to be maintained by Section 17-104 of the Act is:

Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801

The name and address of the registered agent for service of process required to be maintained by Section 17-104 of the Act are:

The Corporation Trust Company
Corporation Trust Center
1209 Orange Street
Wilmington, Delaware 19801

General Partner. The name and the mailing address of the general partner is:

DEP OLPGP, LLC
1100 Louisiana Street, 10th Floor
Houston, Texas 77002

IN WITNESS WHEREOF, the undersigned general partner has duly executed this Certificate of Limited Partnership as of the date first written above.


DEP OLPGP, LLC

By:		Duncan Energy Partners L.P., its Sole Member

	By:		DEP Holdings, LLC, its General Partner

		By:		/s/ Richard H. Bachmann

				Richard H. Bachmann
				President and Chief Executive Officer

exv23w1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the use in this registration statement on Form S-1 of (i) our report dated November 1, 2006 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the preparation of the combined financial statements of Duncan Energy Partners Predecessor from the separate records maintained by Enterprise Products Partners L.P.), relating to the combined financial statements and financial statement schedule of Duncan Energy Partners Predecessor as of December 31, 2005 and 2004 and for each of the three years in the period ended December 31, 2005, (ii) our report dated November 1, 2006, with respect to the balance sheet of Duncan Energy Partners L.P. as of September 30, 2006, and (iii) our report dated November 1, 2006, with respect to the balance sheet of DEP Holdings, LLC as of October 31, 2006 appearing in the prospectus, which is part of this registration statement.

We also consent to the reference to us under the heading “Experts” in such prospectus.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

November 1, 2006