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Duncan Energy Partners L.P. · IPO:  S-1/A · On 1/22/07

Filed On 1/22/07, 6:14am ET   ·   Accession Number 950134-7-927   ·   SEC File 333-138371

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  As Of                Filer                Filing    For/On/As Docs:Size              Issuer               Agent

 1/22/07  Duncan Energy Partners L.P.       S-1/A                 14:5.2M                                   Bowne of Dallas I..01/FA

Initial Public Offering (IPO):  Pre-Effective Amendment to Registration Statement (General Form)   —   Form S-1
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: S-1/A       Amendment No.3 to Form S-1 - Registration No.       HTML   2.38M 
                          333-138371                                             
 2: EX-1.1      Form of Underwriting Agreement                      HTML    224K 
 3: EX-3.6      Amended Limited Liability Company Agreement         HTML    135K 
 4: EX-5.1      Opinion of Andrews Kurth LLP                        HTML     10K 
 5: EX-8.1      Opinion of Andrews Kurth LLP                        HTML     11K 
 6: EX-10.1     Form of Contribution, Conveyance and Assumption     HTML     53K 
                          Agreement                                              
 9: EX-10.13    Form of Amended Limited Liability Company           HTML    172K 
                          Agreement                                              
10: EX-10.15    Form of Amended Limited Liability Company           HTML    156K 
                          Agreement                                              
11: EX-10.18    Form of Fourth Amended Administrative Services      HTML    106K 
                          Agreement                                              
12: EX-10.19    Form of Omnibus Agreement                           HTML     66K 
 7: EX-10.8     Form of Contribution, Conveyance and Assumption     HTML     70K 
                          Agreement                                              
 8: EX-10.9     Form of Contribution, Conveyance and Assumption     HTML     60K 
                          Agreement                                              
13: EX-21.1     List of Subsidiaries                                HTML     16K 
14: EX-23.1     Consent of Deloitte & Touche LLP                    HTML      9K 


S-1/A   —   Amendment No.3 to Form S-1 – Registration No. 333-138371
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Table of Contents
"Summary
"Duncan Energy Partners L.P
"The Offering
"Summary of Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties
"Summary of Certain Risk Factors
"Summary Historical and Pro Forma Financial and Operating Data
"Risk Factors
"Risks Inherent in Our Business
"Risks Inherent in an Investment in Us
"Tax Risks
"Use of Proceeds
"Capitalization
"Dilution
"Cash Distribution Policy and Restrictions on Distributions
"General
"Our Initial Distribution Rate
"Unaudited Pro Forma Combined Available Cash
"Estimated Cash Available to Pay Distributions
"Assumptions and Considerations
"How We Make Cash Distributions
"Distributions of Available Cash
"Distributions of Cash upon Liquidation
"Selected Historical and Pro Forma Financial and Operating Data
"Management's Discussion and Analysis of Financial Condition and Results of Operations
"Overview
"Our Operations
"How We Evaluate Our Operations
"Natural Gas Supply and Outlook
"Factors Affecting Comparability of Future Results
"Results of Operations
"Liquidity and Capital Resources
"Contractual Obligations
"Off-Balance Sheet Arrangements
"Inflation
"Seasonality
"Critical Accounting Policies and Estimates
"Recent Accounting Developments
"Related Party Transactions
"Other Items
"Quantitative and Qualitative Disclosures about Market Risk
"Business
"Our Partnership
"Our Relationship with EPCO and Enterprise Products Partners
"Our Business Strategy
"Our Competitive Strengths
"Industry Overview
"NGL & Petrochemical Storage Services Segment
"Natural Gas Pipelines & Services Segment
"Petrochemical Pipeline Services Segment
"NGL Pipeline Services Segment
"Supplies
"Employees
"Environmental Matters
"Regulation of Operations
"Title to Properties
"Legal Proceedings
"Management
"Governance Matters
"Directors and Executive Officers
"Executive Compensation
"Compensation of Directors of DEP Holdings
"Security Ownership of Certain Beneficial Owners and Management
"Certain Relationships and Related Party Transactions
"Related Party Transactions with Enterprise Products Partners
"Relationships with TEPPCO Partners
"Relationships with Unconsolidated Affiliate
"Contribution, Conveyance and Assumption Agreement
"Omnibus Agreement
"Mont Belvieu Caverns Limited Liability Company Agreement
"Administrative Services Agreement
"Conflicts of Interest, Business Opportunity Agreements and Fiduciary Duties
"Conflicts of Interest and Business Opportunity Agreements
"Fiduciary Duties
"Description of Our Common Units
"Transfer Agent and Registrar
"Transfer of Units
"Description of Material Provisions of Our Partnership Agreement
"Organization and Duration
"Purpose
"Power of Attorney
"Cash Distributions
"Capital Contributions
"Limited Liability
"Voting Rights
"Issuance of Additional Securities
"Amendments to Our Partnership Agreement
"Merger, Sale or Other Disposition of Assets
"Termination or Dissolution
"Liquidation and Distribution of Proceeds
"Withdrawal or Removal of Our General Partner
"Transfer of General Partner Interest
"Transfer of Ownership Interests in Our General Partner
"Change of Management Provisions
"Limited Call Right
"Meetings; Voting
"Status as Limited Partner
"Non-Citizen Assignees; Redemption
"Indemnification
"Resolution of Conflicts of Interest
"Reimbursement of Expenses
"Books and Reports
"Right to Inspect Our Books and Records
"Registration Rights
"Common Units Eligible for Future Sale
"Material Tax Consequences
"Partnership Status
"Limited Partner Status
"Tax Consequences of Unit Ownership
"Tax Treatment of Operations
"Disposition of Common Units
"Uniformity of Units
"Tax-Exempt Organizations and Other Investors
"Administrative Matters
"State, Local and Other Tax Considerations
"Selling Unitholder
"Underwriting
"Validity of the Common Units
"Experts
"Where You Can Find More Information
"Forward-Looking Statements
"Index to Financial Statements
"Unaudited Pro Forma Condensed Combined Financial Statements
"Introduction
"Unaudited Pro Forma Condensed Statement of Combined Operations for the Nine Months Ended September 30, 2006
"Unaudited Pro Forma Condensed Statement of Combined Operations for the Year Ended December 31, 2005
"Unaudited Pro Forma Condensed Combined Balance Sheet at September 30, 2006
"Notes to Unaudited Pro Forma Condensed Combined Financial Statements
"Report of Independent Registered Public Accounting Firm
"Combined Balance Sheets at September 30, 2006, December 31, 2005 and 2004
"Statements of Combined Operations and Comprehensive Income for the Nine Months Ended September 30, 2006 and 2005 (unaudited) and Years Ended December 31, 2005, 2004 and 2003
"Statements of Combined Cash Flows for the Nine Months Ended September 30, 2006 and 2005 (unaudited) and Years Ended December 31, 2005, 2004 and 2003
"Statements of Combined Owners' Net Investment for the Nine Months Ended September 30, 2006 and Years Ended December 31, 2005, 2004 and 2003
"Notes to Combined Financial Statements and Supplemental Schedule
"Balance Sheet at September 30, 2006
"Note to Balance Sheet
"Balance Sheet at October 31, 2006
"Appendix A -- Form of First Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P
"Appendix B -- Glossary of Terms

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Table of Contents

As filed with the Securities and Exchange Commission on January 22, 2007
Registration No. 333-138371
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
AMENDMENT NO. 3
TO
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
 
 
 
 
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.
 



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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 January 22, 2007
 
Prospectus
 
DUNCAN ENERGY PARTNERS L.P. LOGO
 
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 $19.00 and $21.00 per common unit. Before this offering, there has been no public market for our common units. Our common units have been approved for listing, subject to official notice of issuance, on the New York Stock Exchange under the symbol “DEP.”
 
Investing in our common units involves risks. Please read “Risk Factors” beginning on page 21.
 
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 $5.64 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 a fee payable to Lehman Brothers of $1,000,000 in consideration of advice rendered by Lehman Brothers regarding the structure of this offering and our partnership.
 
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 UBS Investment Bank
Citigroup Goldman, Sachs & Co.
Morgan Stanley Wachovia Securities
 
          , 2007



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(MAP)

 



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Table of Contents

 
TABLE OF CONTENTS
 
         
SUMMARY   1
  1
  5
  8
  11
  13
RISK FACTORS   21
  21
  33
  40
USE OF PROCEEDS   42
CAPITALIZATION   43
DILUTION   44
CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS   46
  46
  48
  50
  53
  55
HOW WE MAKE CASH DISTRIBUTIONS   59
  59
  59
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA   60
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS   66
  66
  67
  69
  71
  71
  73
  77
  81
  83
  83
  83
  84
  86
  88
  89
  89



Table of Contents

         
BUSINESS   91
  91
  91
  92
  92
  93
  95
  98
  103
  105
  106
  107
  107
  109
  110
  110
MANAGEMENT   111
  111
  111
  114
  116
  119
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT   120
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS   121
  121
  121
  123
  123
  124
  124
  125
  126
CONFLICTS OF INTEREST, BUSINESS OPPORTUNITY AGREEMENTS AND FIDUCIARY DUTIES   130
  130
  133
DESCRIPTION OF OUR COMMON UNITS   135
  135
  135
DESCRIPTION OF MATERIAL PROVISIONS OF OUR PARTNERSHIP AGREEMENT   137
  137
  137
  137
  137
  137


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  138
  138
  139
  140
  142
  142
  143
  143
  144
  144
  144
  145
  145
  146
  146
  146
  147
  147
  148
  148
  148
  149
  150
  150
  151
  152
  156
  157
  159
  160
  160
  162
  164
  165
  170
  170
  170
  171
  F-1
  A-1
  B-1
 Form of Underwriting Agreement
 Amended Limited Liability Company Agreement
 Opinion of Andrews Kurth LLP
 Opinion of Andrews Kurth LLP
 Form of Contribution, Conveyance and Assumption Agreement
 Form of Contribution, Conveyance and Assumption Agreement
 Form of Contribution, Conveyance and Assumption Agreement
 Form of Amended Limited Liability Company Agreement
 Form of Amended Limited Liability Company Agreement
 Form of Fourth Amended Administrative Services Agreement
 Form of Omnibus Agreement
 List of Subsidiaries
 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


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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.


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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 $20.00 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 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


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  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 consists 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 became operational and began transporting NGLs in January 2007 after undergoing modifications, extensions and interconnections. Additional expansions are scheduled to be completed during the remainder of 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. 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 nine months ended September 30, 2006, Enterprise Products Partners had revenues of $10.6 billion, operating income of $653.7 million and net income of $468.4 million. After giving effect to this offering, we will continue to have a number of commercial relationships, including transportation and storage agreements, with Enterprise Products Partners and its affiliates. In addition, 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 an experienced management team and 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” for more information on these commercial and other relationships.
 
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 7,301,571 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 our new credit agreement, 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;”


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  •  We will become party to an existing administrative services agreement among EPCO and certain of its 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 OLP, pursuant to which Enterprise Products OLP 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 and Mont Belvieu Caverns brine-related facilities. In addition, we will grant Enterprise Products OLP a right of first refusal on the equity interests in certain of our operating subsidiaries and on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business, and a preemptive right with respect to equity securities issued by certain of our subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.
 
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.


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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
 
    General Partner
          Total
 
    Units     Common Units     Ownership  
Public common units
          13,000,000       62.8 %
Enterprise Products Partners and its affiliates
          7,301,571       35.2 %
General partner interest
    414,318             2.0 %
                         
Total
    414,318       20,301,571       100.0 %
                         


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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 20,301,571 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 $1.0 million structuring fee, but before estimated expenses associated with the offering and related formation transactions, to:
 
• distribute approximately $212.3 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 $28.2 million to fund our share of estimated capital expenditures to complete planned expansions to the South Texas NGL pipeline system and brine production and above-ground storage projects at Mont Belvieu subsequent to the closing of this offering; and
 
• pay approximately $2.9 million of other estimated net expenses associated with this offering and related formation transactions described on page 2.
 
In addition, we will borrow approximately $200 million under our new $300 million credit agreement, and we will distribute $198.9 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 will 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. Our ability to pay cash distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption “Cash Distribution Policy and Restrictions on Distributions.” We must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner.


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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 September 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 80% or more 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


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general partner will own approximately 36.0% of our outstanding common units (or approximately 26.4% 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 the record date for distributions for the period ending 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 20% of the cash distributed with respect to that period. For example, if you receive an annual distribution of $1.60 per common unit, we estimate that your average allocated federal taxable income per year will be no more than $0.32 per common 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 Our common units have been approved for listing, subject to official notice of issuance, on the New York Stock Exchange under the symbol “DEP.”


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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 December 31, 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


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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.”
 
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.
 
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 our benefit. 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 our benefit. 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,


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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.”


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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 21. 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.
 
  •  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.
 
  •  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.
 
  •  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 not be able to make acquisitions or to make acquisitions on economically acceptable terms, which may limit our ability to grow.
 
  •  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 available to pay distributions to you.
 
  •  Successful development of LNG import terminals outside our areas of operations 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 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.


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  •  An affiliate of Enterprise Products Partners 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 $5.64 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.


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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 nine months ended September 30, 2006 and for the years ended December 31, 2005, 2004 and 2003 and combined balance sheet data at September 30, 2006 and 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 data for the nine months ended September 30, 2005 and combined balance sheet data at September 30, 2005 is derived from the unaudited condensed combined financial statements of Duncan Energy Partners Predecessor. 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 26.4% 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 nine months ended September 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 September 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 $28.6 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 $18.9 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 expenditure of $21.3 million in connection with the construction of additional brine production capacity and above-ground storage reservoirs at Mont Belvieu. The pro forma financial data does not reflect estimated additional capital expenditures of $14.1 million that will be made by Mont Belvieu Caverns subsequent to December 31, 2006 to complete these projects. We will retain cash in an amount equal to our 66% share (approximately $9.3 million) of these additional capital expenditures from the net proceeds of this offering in order to fund our share of the planned expansion costs.
 
  •  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.


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  •  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 revolving 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.


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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 )     (13,807 )
Other income (expense), net
    1       (52 )                        
                                         
Total other income (expense)
    1       (52 )     (532 )     (532 )     (13,807 )
                                         
Income before parent interest
    52,454       58,124       39,669       33,395       20,120  
Parent’s share of income
                                    (14,274 )
                                         
Income from continuing operations
    52,454       58,124       39,669     $ 33,395     $ 5,846  
                                         
Cumulative effect of change in accounting principle
                    (582 )                
                                         
Net income
  $ 52,454     $ 58,124     $ 39,087                  
                                         
Earnings per unit — public, basic and diluted
                                  $ 0.45  
                                         
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       39,106  
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  


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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 Nine Months
 
    For the Nine Months
    Ended September 30, 2006  
    Ended September 30,     Pro
    Pro Forma
 
    2005     2006     Forma     As Adjusted  
 
Combined Results of Operations Data:(1)
                               
Revenues
  $ 649,404     $ 740,102     $ 733,434     $ 733,434  
Costs and expenses:
                               
Operating costs and expenses
    614,328       697,979       696,511       696,511  
General and administrative expenses
    3,799       2,469       4,344       4,344  
                                 
Total costs and expenses
    618,127       700,448       700,855       700,855  
                                 
Equity in income of unconsolidated affiliates
    280       624       624       624  
                                 
Operating income
    31,557       40,278       33,203       33,203  
                                 
Interest expense
                            (9,930 )
Other income
            6       6       6  
                                 
Total other income (expense)
            6       6       (9,924 )
                                 
Income before provision for income taxes and parent interest
    31,557       40,284       33,209       23,279  
Provision for income taxes
            (21 )     (21 )     (21 )
                                 
Income before parent interest
    31,557       40,263       33,188       23,258  
Parent’s share of net income
                            (15,733 )
                                 
Income from continuing operations
    31,557       40,263     $ 33,188     $ 7,525  
                                 
Cumulative effect of change in accounting principle
            9                  
                                 
Net income
  $ 31,557     $ 40,272                  
                                 
Earnings per unit — public, basic and diluted
                          $ 0.58  
                                 
Combined Balance Sheet Data (at period end):(1)
                               
Total assets
  $ 617,402     $ 747,155     $ 799,675     $ 828,963  
Total debt
                            200,000  
Parent’s interest in the Partnership
                            305,233  
Owners’ net investment
    520,727       662,131       716,465          
Partners’ equity — public
                            240,520  
Other Combined Financial Data:(1)
                               
Net cash flows provided by operating activities
  $ 37,226     $ 62,301                  
Cash flows used in investing activities
    16,669       58,226                  
Cash flows used in financing activities(2)
    20,557       4,075                  
Gross operating margin
    49,611       58,198     $ 52,998     $ 52,998  
EBITDA
    45,810       55,761       48,677       32,944  
Operating Data:(1)
                               
Natural Gas Pipelines & Services, net:
                               
Natural gas throughput volumes (Bbtus/d)
    657       773       773       773  
Petrochemical Pipeline Services, net:
                               
Petrochemical transportation volumes (MBbls/d)
    34       36       36       36  
 
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 summary historical financial data for Duncan Energy Partners Predecessor and in our pro forma financial data. For a description 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.”


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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. Our pro forma balance sheet data reflects assumed capital expenditures of $21.3 million by Mont Belvieu Caverns in connection with the construction of additional brine production capacity and above-ground storage reservoirs. Our pro forma financial data does not reflect estimated additional capital expenditures of $14.1 million that will be made by Mont Belvieu Caverns subsequent to December 31, 2006 to complete these projects. We will retain cash in an amount equal to our 66% share (approximately $9.3 million) of these additional capital expenditures from the net proceeds of this offering in order to fund our share of the planned expansion costs.
 
  •  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 $66.3 million. Our pro forma balance sheet data reflects assumed capital expenditures of $37.7 million, including approximately $8 million spent to acquire a 10-mile pipeline from an affiliate of TEPPCO Partners, to make this pipeline system operational in January 2007. We expect that it will cost an additional $28.6 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 $18.9 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 results of operations data does not reflect any results attributable to the historical activities of these 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 acquired from an affiliate of 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).


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(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.
 
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.


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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     $ 5,846  
Additions to income to derive EBITDA:
                                       
Interest expense
                    532       532       13,807  
Depreciation, accretion and amortization
    17,882       18,374       19,453       19,453       19,453  
                                         
EBITDA
  $ 70,336     $ 76,498     $ 59,072     $ 53,380     $ 39,106  
                                         
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                  
                                         
 


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                Duncan Energy
 
                Partners L.P.  
                For the Nine Months
 
    Duncan Energy
    Ended September 30, 2006  
    Partners Predecessor           Pro
 
    For the Nine Months
          Forma
 
    Ended September 30,     Pro
    As
 
    2005     2006     Forma     Adjusted  
 
Reconciliation of GAAP “operating income” to non-GAAP “gross operating margin”
                               
Operating income
  $ 31,557     $ 40,278     $ 33,203     $ 33,203  
Adjustments to reconcile operating income to gross operating margin:
                               
Depreciation, amortization and accretion in operating costs and expenses
    14,253       15,468       15,468       15,468  
Loss (gain) on sale of assets in operating costs and expenses
    2       (17 )     (17 )     (17 )
General and administrative costs
    3,799       2,469       4,344       4,344  
                                 
Total gross operating margin
  $ 49,611     $ 58,198     $ 52,998     $ 52,998  
                                 
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)
  $ 31,557     $ 40,272     $ 33,188     $ 7,525  
Additions to income to derive EBITDA:
                               
Interest expense
                            9,930  
Provision for income taxes
            21       21       21  
Depreciation, accretion and amortization
    14,253       15,468       15,468       15,468  
                                 
EBITDA
  $ 45,810     $ 55,761     $ 48,677     $ 32,944  
                                 
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
    (280 )     (624 )                
Deferred income tax expense
            21                  
Loss (gain) on sale of assets
    2       (17 )                
Changes in fair market value of financial instruments
    (355 )     65                  
Net effect of changes in operating accounts
    (7,951 )     7,125                  
                                 
Net cash provided by operating activities
  $ 37,226     $ 62,301                  
                                 

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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 prices we obtain for our transportation and storage services;
 
  •  the volumes of natural gas, NGLs and propylene our customers transport or store;
 
  •  the prices of, level of production of, and demand for, natural gas, propylene and NGLs in the markets we serve;
 
  •  the level of competition from other midstream energy companies, as well as from alternative fuels;
 
  •  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.
 
Please read “Cash Distribution Policy and Restrictions on Distributions” for a discussion of how we determine our available cash.
 
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 September 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 fiscal 2005 and the four quarters ended September 30, 2006 would have been approximately $9.9 million and a deficit of $14.1 million, respectively. These amounts would have been sufficient to allow us


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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 September 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 September 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, which may prevent us from making cash distributions during periods when we record net income.
 
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 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;


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  •  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.


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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, including our South Texas NGL pipeline. 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 South Texas NGL and other 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 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, and adverse changes in its related businesses may reduce our revenue, earnings or cash available for distribution.
 
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 reduced.
 
Any adverse changes in the business of Enterprise Products Partners, due to market conditions, sales of assets or otherwise, or the failure of Enterprise Products Partners to renew any of its material agreements with


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us, could reduce our revenue, earnings or cash available for distribution. Please read “Certain Relationships and Related Party Transactions” for a summary of certain of these agreements.
 
The credit and risk profile of our general partner and its owners could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.
 
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 Ratings Services and Moody’s Investors Service 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. The location of our assets and our customers’ assets in the Gulf Coast region makes them particularly vulnerable to hurricane risk.
 
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 and will not cover amounts up to applicable deductibles. As a result of market


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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 up to an additional $100 million, subject to certain conditions and limitations, 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.
 
Our new revolving credit facility will contain operating and financial restrictions, including covenants and restrictions that may be affected by events beyond our control, 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, 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;


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  •  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 revolving 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 Revolving Credit Facility.”
 
Increases in interest rates could materially adversely affect our business, results of operations, cash flows and financial condition.
 
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 September 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.


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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, which may result in delays, increased costs or decreased cash flows.
 
One of the connections between our South Texas NGL pipeline and the Mont Belvieu facility is a pipeline we have leased from TEPPCO Partners. The initial term of this lease will expire on September 15, 2007, and if we are unable to construct our planned replacement pipeline or extend the lease, the operations of our South Texas NGL 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;


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  •  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 not be able to make acquisitions or to make acquisitions on economically acceptable terms, which may limit our ability to grow.
 
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.
 
Acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per unit basis.
 
Even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless reduce our cash from operations on a per unit basis. 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.


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Federal, state or local regulatory measures could materially affect our business, results of operations, cash flows 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.


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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


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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 nine months ended September 30, 2006, Enterprise Products Partners and its affiliates accounted for approximately 9% and 12% of our total combined revenues, respectively. We expect Enterprise Products Partners and its affiliates will account for an increased percentage of our total revenues after this offering. In addition, several of our assets will 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 is Enterprise Products Partners; the only customers on our Lou-Tex Propylene pipeline are ExxonMobil and Shell; the only customer on our Sabine Propylene 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.


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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 or our customers’ 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.


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Under the administrative services agreement that we will enter into at or 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 26.4% 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


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  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.
 
  •  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 80% or more 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


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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 80% or more 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 26.4% 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. 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 in the absence of bad faith by the audit and conflicts committee or our general partner, the resolution, action or terms made, taken or provided in connection with a potential conflict of interest transaction will be conclusive and binding on all persons (including all partners) and will not constitute a breach of the partnership agreement or any standard of care or duty imposed by law;
 
  •  provides the general partner shall not be liable to the partnership or any partner for its good faith reliance on the provisions of the partnership agreement to the extent it has duties, including fiduciary duties, and liabilities at law or in equity;


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  •  generally provides that affiliate transactions and resolutions of conflicts of interest 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 provided to or available from unrelated third parties or be “fair and reasonable” to us;
 
  •  provides that it shall be presumed that the resolution of any conflicts of interest by our general partner or the audit and conflicts committee was not made in bad 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 or our limited partners 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 or, in the case of a criminal matter, acted with knowledge that the conduct was criminal.
 
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 26.4% of our outstanding common units if the underwriters exercise their option to purchase additional common units in full).
 
You will experience immediate and substantial dilution of $5.64 per unit.
 
The assumed initial public offering price of $20.00 per unit exceeds the pro forma net tangible book value of $14.36 per common unit. Based on this assumed initial public offering price, you will incur immediate and substantial dilution of $5.64 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;


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  •  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


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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.
 
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.


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The initial public offering price for the common units will be 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.
 
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 enhance state-tax collections. For example, our operating subsidiaries will be subject to a newly revised Texas franchise tax (the “Texas Margin Tax”) on the portion of their 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 the operating subsidiaries’ gross revenue that is apportioned to Texas. If any additional state were to impose a tax upon us or the operating subsidiaries 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.


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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 own property or conduct business in Louisiana and Texas. 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.


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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 underwriting discounts and commissions and a $1.0 million structuring fee, but before estimated net expenses associated with the offering and related formation transactions.
 
We intend to use the net proceeds from this offering to:
 
  •  distribute approximately $212.3 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 $28.2 million to fund our 66% share of estimated capital expenditures to complete planned expansions to the South Texas NGL pipeline system and brine production and above-ground storage projects at Mont Belvieu subsequent to the closing of this offering; and
 
  •  pay approximately $2.9 million of other estimated net expenses associated with this offering and related formation transactions described on page 2.
 
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 and Mont Belvieu Caverns will have recorded $59 million of a total estimated additional cost of $101.7 million to complete our acquisition and construction of the South Texas NGL pipeline system and our completion of brine production and above-ground storage projects at Mont Belvieu. 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) $101.7 million (the estimated total additional costs); and
 
  (2)  the actual construction and acquisition costs paid with respect to (i) the South Texas NGL pipeline (excluding the original pipeline purchase costs of approximately $97.7 million) and (ii) the Mont Belvieu brine production and above-ground storage projects, prior to the contribution of interests in South Texas NGL and Mont Belvieu Caverns to us at the closing of this offering.
 
Of the $59 million in total estimated costs noted above, as of December 31, 2006, we had recorded $19.6 million of the estimated additional costs for construction and acquisition of the South Texas NGL pipeline system and $21.3 million of the estimated additional costs related to the Mont Belvieu brine production and above-ground storage projects.
 
If the offering price is more or less than the assumed $20.00 per unit price, the amount that we will actually distribute to Enterprise Products OLP will also be increased or decreased by all of the difference in such net proceeds from this offering.
 
Concurrently with the closing of this offering, we will also borrow approximately $200 million under our new $300 million credit agreement. We will distribute $198.9 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 Revolving 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” and “Security Ownership of Certain Beneficial Owners and Management.”


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CAPITALIZATION
 
The following table sets forth:
 
  •  the cash and capitalization of our predecessor, Duncan Energy Partners Predecessor, as of September 30, 2006 on a combined historical basis;
 
  •  our pro forma cash and capitalization as of September 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 and 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 in January 2007;
 
  •  the payment of estimated additional costs of $21.3 million required to expand our Mont Belvieu brine production capacity and above-ground storage reservoirs;
 
  •  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 September 30, 2006, after giving effect to the transactions described above, this offering, the borrowing of approximately $200 million under a new $300 million 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 September 30, 2006  
                Pro Forma,
 
    Historical     Pro Forma     As Adjusted  
    (Dollars in thousands)  
 
Cash
  $     $     $ 28,188 (a)
                         
Debt
                200,000  
Owner’s net investment — predecessor
    662,131       716,465        
Parent’s interest in Partnership
                305,233  
Partnership equity — common units — public
                240,520  
                         
Total capitalization
  $ 662,131     $ 716,465     $ 745,753  
                         
 
 
  (a)  Represents cash retained for our 66% share of estimated 2007 capital expenditures to complete planned expansions of our South Texas NGL pipeline and Mont Belvieu brine-related facilities.


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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 September 30, 2006, after giving effect to the offering of 13,000,000 common units, our net tangible book value was $297.5 million, or $14.36 per common unit. This amount includes equity from new investors of $240.5 million and the parent’s interest in common units and the general partner interest of $61.6 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)
  $ 60.68          
Decrease in net tangible book value per common unit attributable to purchasers in the offering
    46.32          
                 
Less: Pro forma net tangible book value per common unit after the offering(2)
            14.36  
                 
Immediate dilution in net tangible book value per common unit to purchasers in the offering
          $ 5.64  
                 
 
 
(1) Determined by dividing the net tangible book value of the contributed net assets of $468.2 million, net of subsidiary ownership interests retained by parent of $243.6 million, by the number of common units (7,301,571 common units and the 2% general partner interest, which has a dilutive effect equivalent to 414,318 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 20,301,571 divided by 98%) by our general partner’s 2% general partner interest.
 
(2) Determined by dividing our pro forma net tangible book value of $297.5 million, which reflects the application of the assumed net proceeds of this offering, by the total number of common units (20,301,571 common units and the 2% general partner interest, which has a dilutive effect equivalent to 414,318 common units) to be outstanding after the offering. The following table shows our calculation of pro forma net tangible book value (dollars in thousands):
 
         
Pro forma net book value, including Parent interest
  $ 302,155  
Less: 66% share of intangible assets attributable to parent’s interest in common units and the general partner interest and new investors
    (4,636 )
         
Pro forma net tangible book value, including Parent interest
  $ 297,519  
         
 
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)
    7,715,889       37.2 %   $ 61,635       20.4 %
New investors
    13,000,000       62.8 %     240,520       79.6 %
                                 
Total
    20,715,889       100.0 %   $ 302,155       100.0 %
                                 
 
 
(1) Upon the consummation of this offering, Enterprise Products OLP and our general partner will own an aggregate of 7,301,571 common units and a 2% general partner interest having a dilutive effect equivalent to 414,318 common units.


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(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 September 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):
 
         
Pro forma owners’ net investment
  $ 716,465  
Less: Payment to Parent from the net proceeds of the offering and borrowings under the credit agreement
    (411,232 )
Less: Parent retention of 34% of the equity interests in contributed subsidiaries of the Partnership
    (243,598 )
         
Total consideration for Parent’s interest in common units and general partner interest
  $ 61,635  
         
 
For financial reporting purposes, the parent’s retained interest in the subsidiaries of $243.6 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.


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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 nine months ended September 30, 2006, our unaudited historical financial statements for the nine months ended September 30, 2005, and our unaudited pro forma condensed combined financial information at September 30, 2006 and for the year ended December 31, 2005 and nine months ended September 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 revolving 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 new credit facility. Specifically, our revolving credit facility contains certain material financial tests, such as a Consolidated Debt to Consolidated EBITDA ratio, or leverage ratio, not to exceed 4.75 to 1.00 and a Consolidated EBITDA to Consolidated Interest Expense ratio, or interest coverage ratio, of not less than 2.75 to 1.00, and other covenants that we must satisfy. Should we be unable to satisfy these restrictions under our revolving credit facility, or if we otherwise default under our revolving 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 Revolving 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


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  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 the absence of bad 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 with the consent of the general partner and 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:
 
  •  A reduction in throughput volumes on our pipelines would decrease our cash receipts from pipeline transportation revenues, which would reduce cash available to pay distributions.
 
  •  An increase in operating expenses, general and administrative costs and state and federal income taxes would increase our cash outlays for such items, which would reduce cash available to pay distributions.
 
  •  Principal repayments (to the extent not refinanced) and interest payments on any current or future debt would generally be made from cash generated by operating activities, which would reduce cash available to pay distributions.
 
  •  Capital expenditures reduce cash available to pay distributions to the extent such amounts are funded from cash generated by operating activities.
 
  •  To the extent not funded by borrowings under our revolving credit facility, working capital needs for such items as inventory or prepaid items reduce cash available to pay distributions.
 
Please read “Risk Factors” for additional 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 revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional


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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 held by parent (Enterprise Products OLP)
  $ 2,141     $ 8,562  
Common units held by public unitholders (non-parent)
    5,980       23,920  
General partner interest
    166       663  
                 
Total
  $ 8,287     $ 33,145  
                 
 
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 to the extent we have available cash in accordance with the terms of our partnership agreement, we will 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.


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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 September 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 September 30, 2006 would have been a deficit of $14.1 million. This amount would have been insufficient by approximately $47.2 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 became operational in January 2007 and is expected to 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 growth 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 September 30, 2006, pro forma available cash was reduced by $19.5 million and $61.1 million for capital expenditures in those respective periods. We expect that, in the future, growth capital expenditures will be funded with sources other than cash from operations, such as proceeds from this offering, borrowings under our new revolving 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 on such information or its achievability, and assume no responsibility for, and disclaim any association with the prospective financial information. 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


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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 September 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 adjustments in the following table give effect to (i) the contribution of 66% of the ownership interests in Mont Belvieu Caverns, Acadian Gas, Sabine Propylene and Lou-Tex Propylene, (ii) the revision of related party storage contracts with Enterprise Products Partners, including terms relating to the allocation of measurement gains and losses, (iii) the execution of a limited liability company agreement with Mont Belvieu Caverns providing for special allocations to Enterprise Products Partners, and (iv) the assignment of certain third-party propylene transportation agreements, as if they had occurred at the beginning of the periods presented.


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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,
    September 30,
 
    2005     2006  
 
Cash Provided by Operating Activities(a)
  $ 40,568     $ 65,643  
Adjustments to derive Consolidated Adjusted EBITDA(a):
               
Interest expense
    532       532  
Equity income of unconsolidated affiliates
    331       675  
Net effect of changes in operating accounts(b)
    18,280       3,204  
Changes in fair market value of financial instruments for Acadian Gas
    (52 )     (472 )
Non-cash gain (loss) on sale of assets
    (5 )     14  
                 
Consolidated Adjusted EBITDA
    59,654       69,596  
Pro forma increase in storage revenues(c)
    11,610       12,902  
Pro forma decrease in operating expense due to allocation of measurement losses by parent(d)
    3,055       2,053  
Pro forma decrease in transportation revenues(e)
    (18,439 )     (21,238 )
Additional expenses of being a public company(f)
    (2,500 )     (2,500 )
                 
Pro Forma Consolidated Adjusted EBITDA
    53,380       60,813  
Less: Cash interest expense(g)
    (13,000 )     (13,000 )
Cash distributions to parent by subsidiaries(h)
    (13,100 )     (737 )
Parent contribution (distribution) for operating losses(d)
    2,122       (49 )
Capital expenditures(i)
    (19,472 )     (61,083 )
                 
Pro Forma Combined Available Cash
  $ 9,930     $ (14,056 )
                 
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
    8,562       8,562  
                 
Total cash distributions
  $ 33,145     $ 33,145  
                 
(Shortfall)
  $ (23,215 )   $ (47,201 )
                 
Debt Covenant Ratios
               
Leverage ratio(j)
    5.56       5.07  
Interest coverage ratio(j)
    2.66       2.91  
 
 
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 September 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 new $300 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


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needs. We expect to have $100 million of additional borrowing capacity under our revolving credit facility immediately after giving effect to this offering and the transactions contemplated at the closing. 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 resulting from an assumed $200 million borrowed at an estimated variable interest rate of 6.5% per annum under our $300 million revolving 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.
 
(j) With the exception of meeting the interest coverage ratio for the pro forma four quarters ending September 30, 2006, we would not have been in compliance with the expected financial covenants of our new revolving credit facility. These financial tests and covenants are described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — New Revolving Credit Facility.” The reason for this compliance shortfall is the lack of pro forma EBITDA from our South Texas NGL pipeline, which became operational in January 2007. Prior to the consummation 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 this pipeline system. Please read “Business — NGL Pipeline Services Segment — Customer and Related Party Contract and “Certain Relationships and Related Party Transactions — Related Party Transactions with Enterprise Products Partners.”


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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. 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 $16.3 million higher than Pro Forma Consolidated Adjusted EBITDA for the four quarters ended September 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.


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In the following table entitled “Estimated Cash Available to Pay Distributions,” we estimate that our Estimated Consolidated Adjusted EBITDA will be approximately $77.1 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
  $ 77,073  
Less: Cash interest expense(a)
    (13,000 )
      Cash distributions to parent by subsidiaries(b)
    (25,059 )
      Sustaining capital expenditures(c)
    (5,869 )
         
Estimated Cash Available to Pay Distributions
  $ 33,145  
         
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
    8,562  
         
Total estimated cash distributions
  $ 33,145  
         
Debt Covenant Ratios
       
Leverage ratio(d)
    4.0 x
Interest coverage ratio(d)
    3.9 x
 
 
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 revolving 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 $18.9 million net to us for the expansion of the South Texas NGL pipeline system and $9.3 million net to us for the expansion of brine production capacity and above-ground storage reservoirs at Mont Belvieu, 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 new revolving credit facility, equity or debt financings, or contributions from Enterprise Products OLP, or any other growth capital expenditures.
 
(d) Based on the terms of our new revolving credit facility, we believe that we will be in compliance with our financial covenants during 2007. These financial tests and covenants are described under “Management’s


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Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — New Revolving Credit Facility.”
 
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 new revolving 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 September 30, 2006.
 
                         
          Four Quarters
    Four Quarters
 
    Year Ended
    Ended
    Ending
 
    December 31,
    September 30,
    December 31,
 
    2005     2006     2007  
 
Operating data (on a 100% basis): (a) 
                       
Natural gas throughput, net (Bbtu/d)(b)
    640       728       700  
NGL transportation, net (MBPD)(c)
                    68  
Petrochemical transportation, net (MBPD)(d)
    33       35       37  
Pro forma segment revenues (dollars in millions):
                       
Natural Gas Pipelines & Services(e)
  $ 866.7     $ 947.6     $ 738.4  
NGL & Petrochemical Storage Services(f)
    64.4       72.5       75.8  
NGL Pipeline Services(c)
                    20.6  
Petrochemical Pipeline Services(d)
    15.5       15.7       14.9  
                         
Total pro forma revenues
  $ 946.6     $ 1,035.8     $ 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 September 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


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2007 on the Acadian Gas system are expected to be 60 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 September 30, 2006.
 
(c) The South Texas NGL pipeline became operational in January 2007. No volumetric data or revenue information is provided for the year ended December 31, 2005 and four quarters ended September 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 September 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 $8.85 per MMBtu for the year ended December 31, 2005 and four quarters ended September 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 December 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 $7.07 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 $3.3 million higher than those presented for the four quarters ended September 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 September 30, 2006.
 
                         
          Four Quarters
    Four Quarters
 
    Year Ended
    Ended
    Ending
 
    December 31,
    September 30,
    December 31,
 
    2005     2006     2007  
 
Pro forma cost and expense data (dollars in millions):
                       
Cost of natural gas sales(a)
  $ 836.5     $ 920.5     $ 706.9  
Operating costs and expenses, excluding non-cash costs(b)
    50.0       49.5       59.2  
General and administrative costs, including pro forma incremental public company costs(c)
    7.0       5.7       6.5  
                         
Total
  $ 893.5     $ 975.7     $ 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.


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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 September 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 December 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 $7.07 per MMBtu in 2007.
 
(b) We forecast our operating costs and expenses, excluding non-cash costs, for the four quarters ending December 31, 2007 to approximate $59.2 million. This amount is $9.2 million higher than pro forma operating costs and expenses for the year ended December 31, 2005 and $9.7 million higher than those for the four quarters ended September 30, 2006. The 2007 period includes $3.7 million of operating costs and expenses associated with our South Texas NGL pipeline system, which became operational 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 million lower than those for the four quarters ended September 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 $61.1 million for the four quarters ended September 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 $38.2 million of capital expenditures for the year ended December 31, 2005 and nine months ended September 30, 2006. All of these projects are estimated to be completed and placed in service by the end of the first quarter of 2007. The remainder of combined capital spending for the year ended December 31, 2005 and nine months ended September 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 $28.6 million to complete planned expansions (Phase II) to the South Texas NGL pipeline system. In addition, we expect that Mont Belvieu Caverns will make additional capital expenditures of $14.1 million to complete brine production and above-ground storage projects. We expect to fund our 66% share of these expenditures (approximately $28.2 million) with proceeds from this offering. We may also incur $25 million to $75 million of additional growth 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 new revolving 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.


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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 $300 million revolving 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.
 
Supplemental Forecast Data
 
Our forecast of total gross operating margin for the four quarters ending December 31, 2007 is approximately $83.6 million. A reconciliation of forecast GAAP operating income for 2007 to forecast non-GAAP gross operating margin in total is as follows:
 
         
Revenues
  $ 849,692  
Costs and expenses:
       
Cash costs and expenses
    772,620  
Depreciation and amortization
    26,877  
         
Total costs and expenses
    799,497  
         
Operating income
    50,195  
Adjustments to derive non-GAAP forecast gross operating margin:
       
Add general and administrative costs, including pro forma incremental public company costs
    6,569  
Add non-cash depreciation and amortization
    26,877  
         
Gross operating margin in total
  $ 83,641  
         
 
For a description of non-GAAP gross operating margin, please read “Summary — Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.” On a percentage basis, we expect forecast gross operating margin by segment for 2007 to approximate 49% for the NGL and Petrochemical Storage Services segment, 20% for the NGL Pipeline Services segment, 18% for the Natural Gas Pipelines and Services segment, and 13% for the Petrochemical Pipeline Services segment.


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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.


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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 nine months ended September 30, 2006 and for the years ended December 31, 2005, 2004 and 2003 and combined balance sheet data at September 30, 2006 and 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 data for the nine months ended September 30, 2005 and combined balance sheet data at September 30, 2005 is derived from the unaudited condensed combined financial statements of Duncan Energy Predecessor. 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 26.4% 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 gives 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 spent to acquire a pipeline asset from an affiliate of TEPPCO Partners, to make this system operational in January 2007. The pro forma financial data does not reflect estimated additional capital expenditures of $28.6 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 $18.9 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 expenditure of $21.3 million in connection with the construction of additional brine production capacity and above-ground storage reservoirs at Mont Belvieu. The pro forma financial data does not reflect estimated additional capital expenditures of $14.1 million that will be made by Mont Belvieu Caverns subsequent to December 31, 2006 to complete these projects. We will retain cash in an amount equal to our 66% share (approximately $9.3 million) of these additional capital expenditures from the net proceeds of this offering in order to fund our share of the planned expansion costs.
 
  •  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


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  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 $300 million revolving 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 nine months ended September 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 September 30, 2006 for the balance sheet data.


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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 )     (13,807 )
Other income (expense), net
    448       113       1       (52 )                        
                                                         
Total other income (expense)
    448       113       1       (52 )     (532 )     (532 )     (13,807 )
                                                         
Income before parent interest
    37,169       55,411       52,454       58,124       39,669       33,395       20,120  
Parent’s share of income
                                                    (14,274 )
                                                         
Income from continuing operations
    37,169       55,411       52,454       58,124       39,669     $ 33,395     $ 5,846  
                                                         
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
                                                  $ 0.45  
                                                         
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       39,106  
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       36       40       39       33       33       33  


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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 Nine Months
 
    For the Nine Months
    Ended September 30, 2006  
    Ended September 30,     Pro
    Pro Forma
 
    2005     2006     Forma     As Adjusted  
 
Combined Results of Operations Data:(1)
                               
Revenues
  $ 649,404     $ 740,102     $ 733,434     $ 733,434  
Costs and expenses:
                               
Operating costs and expenses
    614,328       697,979       696,511       696,511  
General and administrative expenses
    3,799       2,469       4,344       4,344  
                                 
Total costs and expenses
    618,127       700,448       700,855       700,855  
                                 
Equity in income of unconsolidated affiliates
    280       624       624       624  
                                 
Operating income
    31,557       40,278       33,203       33,203  
                                 
Interest expense
                            (9,930 )
Other income
            6       6       6  
                                 
Total other income (expense)
            6       6       (9,924 )
                                 
Income before provision for income taxes and parent interest
    31,557       40,284       33,209       23,279  
Provision for income taxes
            (21 )     (21 )     (21 )
                                 
Income before parent interest
    31,557       40,263       33,188       23,258  
Parent’s share of income
                            (15,733 )
                                 
Income from continuing operations
    31,557       40,263     $ 33,188     $ 7,525  
                                 
Cumulative effect of change in accounting principle
            9                  
                                 
Net income
  $ 31,557     $ 40,272                  
                                 
Earnings per unit — public, basic and diluted
                          $ 0.58  
                                 
Combined Balance Sheet Data (at period end):(1)
                               
Total assets
  $ 617,402     $ 747,155     $ 799,675     $ 828,963  
Total debt
                            200,000  
Parent’s interest in the Partnership
                            305,233  
Owners’ net investment — predecessor
    520,727       662,131       716,465          
Partners’ equity — public
                            240,520  
Other Combined Financial Data:(1)
                               
Net cash flows provided by operating activities
  $ 37,226     $ 62,301                  
Cash flows used in investing activities
    16,669       58,226                  
Cash flows used in financing activities(2)
    20,557       4,075                  
Gross operating margin
    49,611       58,198     $ 52,998     $ 52,998  
EBITDA
    45,810       55,761       48,677       32,944  
Operating Data:(1)
                               
Natural Gas Pipelines & Services, net:
                               
Natural gas throughput volumes (Bbtus/d)
    657       773       773       773  
Petrochemical Pipeline Services, net:
                               
Petrochemical transportation volumes (MBbls/d)
    34       36       36       36  


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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.”
 
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 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. Our pro forma balance sheet data reflects assumed capital expenditures of $21.3 million by Mont Belvieu Caverns in connection with the construction of additional brine production capacity and above-ground storage reservoirs. Our pro forma financial statements do not reflect estimated additional capital expenditures of $14.1 million that will be made by Mont Belvieu Caverns subsequent to December 31, 2006 to complete these projects. We will retain cash in an amount equal to our 66% share of the additional capital expenditures (approximately $9.3 million) from the net proceeds of this offering in order to fund our share of the planned expansion costs.
 
  •  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 purchase price for this asset was approximately $97.7 million. This pipeline system will be contributed to 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 $66.3 million. Our pro forma balance sheet data reflects assumed capital expenditures of $37.7 million, including $8 million spent to acquire a 10-mile pipeline from an affiliate of TEPPCO Partners, to make this system operational in January 2007. We expect that it will cost an additional $28.6 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 $18.9 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. The pro forma combined results of operations data does not reflect any results of operations attributable to the historical activities of the existing NGL 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.
 
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


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the pipeline was out of service when we acquired it. With respect to the 10-mile pipeline acquired from an affiliate of 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.


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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. For the period discussed below, our operations were 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 became operational in January 2007. This business will be accounted for under a fourth reporting segment, NGL Pipeline Services. The South Texas NGL pipeline system consists 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 operations for this pipeline segment.
 
Our operating revenues from each of our segments (other than our NGL Pipeline Services segment which became operational in January 2007), and their relative percentages of our total revenues, consisted of the following (dollars in millions):
 
                                                                                 
          Nine Months Ended
 
    Year Ended December 31,     September 30,  
    2005     2004     2003     2006     2005  
 
Revenues:
                                                                               
NGL & Petrochemical Storage Services
  $ 52.8       5%     $ 49.5       7%     $ 49.4       7%     $ 43.2       6%     $ 36.4       6%  
Natural Gas Pipelines & Services
    866.7       91%       658.4       88%       576.5       86%       668.7       90%       587.8       90%  
Petrochemical Pipeline Services
    33.9       4%       41.0       5%       42.3       7%       28.2       4%       25.2       4%  
                                                                                 
Total revenues
  $ 953.4       100%     $ 748.9       100%     $ 668.2       100%     $ 740.1       100%     $ 649.4       100%  
                                                                                 


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Our gross operating margin by business segment and in total is as follows for the periods indicated (dollars in thousands):
 
                                                                                 
          Nine Months Ended
 
    Year Ended December 31,     September 30,  
    2005     2004     2003     2006     2005  
 
NGL & Petrochemical Storage Services(1)
  $ 16,636       26%     $ 19,843       24%     $ 19,838       26%     $ 15,080       26%     $ 7,824       16%  
Natural Gas Pipelines & Services(1)
    18,939       30%       25,256       31%       18,272       24%       17,058       29%       19,667       40%  
Petrochemical Pipeline Services(1)
    28,567       44%       36,886       45%       38,363       50%       26,060       45%       22,120       44%  
                                                                                 
Total segment gross operating margin(1)
  $ 64,142       100%     $ 81,985       100%     $ 76,473       100%     $ 58,198       100%     $ 49,611       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 became 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).
 
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 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.


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We evaluate pricing, volume and availability for storage on a case-by-case basis. Segregated storage allows a customer to reserve 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 45% and 55%, respectively, of the average daily gas volumes for the first nine 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 Propylene pipeline. We have entered into separate product exchange agreements with Shell and ExxonMobil through which we agree to receive


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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 Propylene 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 consists 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 was placed into operation and began transporting NGLs in January 2007, after undergoing modifications, extensions and interconnections. Additional expansions are scheduled to be completed during the remainder of 2007.
 
The sole customer of our NGL Pipeline Services segment is 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.
 
Prior to 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 nine months ended September 30, 2006, the Shoup and Armstrong fractionation plants collectively produced 65,884 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


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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 Propylene and Sabine Propylene 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.”
 
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:
 
  •  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.


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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 acquired by an affiliate of Enterprise Products Partners from an affiliate of TEPPCO Partners for $8 million and subsequently contributed to us, and a 12-mile pipeline leased from TEPPCO Partners until planned completion during the third quarter of 2007 of a parallel 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 acquired by an affiliate of Enterprise Products Partners from an affiliate of TEPPCO Partners and contributed to us 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).


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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 revolving 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 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 the 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 storage revenues is $9.8 million for the nine months ended September 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 $2.5 million for the nine months ended September 30, 2006 and 2005, respectively. At September 30, 2006, the financial statements of Duncan Energy Partners Predecessor included $1.8 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 $1.0 million charge and a $3.2 million charge for the nine months ended September 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 nine months ended September 30, 2006, we did not experience any significant physical loss of product due to a loss of cavern integrity.


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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 $16.5 million for the nine months ended September 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 Nine Months
 
    Year Ended December 31,     Ended September 30,  
    2005     2004     2003     2006     2005  
 
Revenues
  $ 953,397     $ 748,931     $ 668,234     $ 740,102       649,404  
Operating costs and expenses
    909,044       685,544       609,774       697,979       614,328  
General and administrative costs
    4,483       5,442       6,138       2,469       3,799  
Equity in income of unconsolidated affiliates
    331       231       131       624       280  
Operating income
    40,201       58,176       52,453       40,278       31,557  
Net income
    39,087       58,124       52,454       40,272       31,557  
 
Comparison of Nine Months Ended September 30, 2006 with Nine Months Ended September 30, 2005
 
Combined Revenues.  Combined revenues for the first nine months of 2006 were $740.1 million compared to $649.4 million for the first nine months of 2005. The period-to-period increase in combined revenues is primarily due to a $79.9 million increase in revenues associated with natural gas marketing activities, which benefited from higher natural gas sales volumes and prices. In addition, revenues from the NGL & Petrochemical Storage Services segment increased $6.8 million period-to-period primarily due to higher storage volumes.
 
Combined Costs and Expenses.  Combined operating costs and expenses were $698 million for the first nine months of 2006 compared to $614.3 million for the first nine months of 2005. The period-to-period increase in costs and expenses is primarily due to an $84 million increase in purchase costs associated with our natural gas marketing activities. General and administrative costs decreased $1.3 million period-to-period.
 
Changes in our combined revenues and costs and expenses period-to-period are explained in part by changes in energy commodity prices. In general, higher natural gas prices result in an increase in our combined revenues attributable to the sale of natural gas by Acadian Gas; however, these same commodity prices also increase the associated cost of sales as purchase prices rise. The Henry Hub market price of natural


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gas averaged $7.47 per MMBtu for the first nine months of 2006 versus $7.18 per MMBtu for the first nine months of 2005.
 
To a lesser extent, changes in our revenues and costs and expenses are attributable to demand for NGL and petrochemical storage services and activity on our propylene pipelines. Demand for storage services affects the reservation, excess storage and throughput fees earned by our NGL and petrochemical storage business. In turn, demand for our storage services is driven by such factors such as demand for petrochemical feedstocks by the petrochemical industry and the quantity of NGLs extracted from natural gas streams at regional gas processing facilities.
 
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 $15.1 million for the first nine months of 2006 compared to $7.8 million for the first nine months of 2005. Revenues increased $6.8 million period-to-period primarily due to (i) higher excess storage and throughput fees and (ii) brine production revenues. Operating costs and expenses decreased $0.5 million period-to-period attributable to reduced measurement losses in 2006 compared to 2005, which were partially offset by higher utility and maintenance costs.
 
Storage revenues for the first nine months of 2006 were $5.5 million higher than the first nine months of 2005 primarily due to an increase in excess storage and throughput fees. These fees were higher period-to-period due to an increase in storage volumes. We attribute the increase in storage volumes to strong demand for petrochemical feedstocks by the petrochemical industry and improved NGL processing economics. Strong NGL processing economics in recent years have increased the quantity of NGLs extracted from natural gas streams at regional gas processing facilities, which increases the demand for storage services. Also, brine production revenues increase $1.2 million period-to-period, which reflects contractual changes made to the sales agreements with our customers during 2006.
 
Gross operating margin from the Natural Gas Pipelines & Services segment was $17.1 million for the first nine months of 2006 versus $19.7 million for the first nine months of 2005. Natural gas transportation volumes increased to 773 Bbtu/d during the first nine months of 2006 from 657 Bbtu/d during the same period in 2005. Gross operating margin decreased $2.6 million period-to-period primarily due to lower margins on natural gas sales during the first nine months of 2006 relative to the same period of 2005. Also, gross operating margin for the first nine months of 2006 includes a $2.3 million benefit from the collection of a contingent asset related to a prior business acquisition. Equity earnings from our investment in Evangeline increased $0.3 million period-to-period.
 
We realized higher natural gas sales margins during the first nine months of 2005, as compared to the same period in 2006, primarily due to the effects of Hurricane Katrina. This hurricane impacted supply and demand for natural gas, NGLs, crude oil and motor gasoline. In general, this resulted in an increase in energy commodity prices, which was exacerbated in certain regions due to local supply and demand imbalances. Our natural gas sales margins, subsequent to Hurricane Katrina, benefited from increased regional demand for natural gas and the general increase in commodity prices.
 
Gross operating margin from the Petrochemical Pipeline Services segment was $26.1 million for the first nine months of 2006 compared to $22.1 million for the first nine months of 2005. Petrochemical transportation volumes were 36 MBPD during the first nine months of 2006 versus 34 MBPD during the 2005 period. Transportation revenues increased $3.1 million period-to-period primarily due to higher transportation volumes and a higher average transportation fee on our Lou-Tex Propylene pipeline. Operating costs and expenses decreased $0.9 million period-to-period primarily due to a reduction in property taxes associated with the Lou-Tex Propylene pipeline. During 2006, we successfully negotiated a lower property tax rate with the Louisiana state taxing authority, which we estimate will provide an annual benefit of approximately $1.9 million in 2006.
 
The Lou-Tex Propylene pipeline transports chemical-grade propylene from multiple receipt points to multiple delivery points. The contractual transportation fee we charge our customers is based upon the


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distance that product moves through the Lou-Tex Propylene pipeline. During the first nine months of 2006 compared to the same period of 2005, we earned a higher average transportation fee due to our customers’ election to move chemical-grade propylene over a greater distance through the Lou-Tex Propylene pipeline.
 
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.
 
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.
 
Changes in our combined revenues and costs and expenses period-to-period are explained in part by changes in energy commodity prices. In general, higher natural gas prices result in an increase in our combined revenues attributable to the sale of natural gas by Acadian Gas; however, these same commodity prices also increase the associated cost of sales as purchase prices rise. The Henry Hub market price of natural gas averaged $8.64 per MMBtu during 2005 versus $6.13 per MMBtu during 2004.
 
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. Revenues increased $3.3 million year-to-year primarily due to higher excess storage and throughput fees. These fees were higher in 2005 compared to 2004 due an increase in storage volumes, which resulted from strong demand for petrochemical feedstocks by the petrochemical industry and improved NGL processing economics. The $3.3 million increase in revenues was offset by a $6 million year-to-year increase in operating costs and expenses primarily due to higher utility costs and higher measurement losses recognized in 2005.
 
Historically, operating costs and expenses of our NGL and petrochemical storage business have been affected each period by measurement gains and losses. Operating costs and expenses reflect measurement losses of $5.2 million for 2005 compared to losses of $0.4 million for 2004. Prospectively, effective concurrent with the closing of this offering, we will specifically allocate to Enterprise Products Partners any items of income and gain or loss and deduction relating to net measurement gains and losses. Accordingly, in the future, these measurement gains and losses should not affect our net income or have a significant impact on us with respect to our cash flows or operating activities.
 
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 throughput was 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 relative to 2004. In general, Acadian Gas purchases natural gas at prices that are based upon the Henry Hub index. In turn, Acadian Gas generally wholesales natural gas to its customers at the Henry Hub price plus a contractual margin. Acadian Gas’ natural gas sales contract with Evangeline contains a provision whereby a portion of the contractual margin is determined through a comparison of (i) Acadian Gas’s annual weighted average natural gas purchase cost to (ii) a benchmark determined by reference to a weighted average grouping of natural gas market indices. As a result of this benchmarking mechanism, we realized $4.8 million in higher natural gas sales margins in 2004 relative to 2005. In addition, operating costs and expenses increased $1.7 million year-to-year primarily due to higher


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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 operating margin decreased $8.3 million year-to-year primarily due to reduced transportation volumes on our Lou-Tex Propylene pipeline. 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 noncash 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.
 
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.
 
Changes in our combined revenues and costs and expenses period-to-period are explained in part by changes in energy commodity prices. In general, higher natural gas prices result in an increase in our combined revenues attributable to the sale of natural gas by Acadian Gas; however, these same commodity prices also increase the associated cost of sales as purchase prices rise. The Henry Hub market price of natural gas averaged $6.13 per MMBtu during 2004 versus $5.38 per MMBtu during 2003.
 
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. Revenues and 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 throughput 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. Higher natural gas sales margins, primarily due to the benchmarking mechanism in Acadian Gas’ natural gas sales contract with Evangeline, accounted for $3.6 million of the period-to-period increase in gross operating margin. Approximately $1.7 million of the period-to-period increase in gross operating margin is attributable to higher transportation volumes in 2004 compared to 2003. Also, 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.


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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 revolving 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 revolving 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 Nine Months
 
    For Year Ended December 31,     Ended September 30,  
    2005     2004     2003     2006     2005  
 
Net cash provided by operating activities
  $ 40,568     $ 79,463     $ 64,732     $ 62,301     $ 37,226  
Net cash used in investing activities
    19,503       6,931       340       58,226       16,669  
Net cash used in financing activities
    21,065       72,532       64,392       4,075       20,557  
 
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 paid $4.1 million and $20.6 million in net cash distributions during the first nine months of 2006 and 2005, respectively.
 
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 Nine Months Ended September 30, 2006 with Nine Months Ended September 30, 2005
 
Operating activities.  Net cash provided by operating activities was $62.3 million for the first nine months of 2006 compared to $37.2 million for the first nine months of 2005. The $25.1 million increase in net cash provided by operating activities is primarily due to higher earnings for the first nine 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 nine month periods, please read “— Results of Operations” above.
 
Investing activities.  Cash used in investing activities was $58.2 million for the first nine months of 2006 compared to $16.7 million for the first nine months of 2005. The $41.5 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 distributions to owners were $4.1 million for the first nine months of 2006 compared to $20.6 million for the first nine months of 2005. The net change in cash distributions


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resulted from an increase in cash provided by operating activities and an increase in cash used for capital expenditures for the first nine months of 2006.
 
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.


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The following table summarizes our expenditures for pipeline integrity costs for the periods indicated (dollars in thousands):
 
                                         
          For the Nine
 
          Months
 
    For Year Ended December 31,     Ended September 30,  
    2005     2004     2003     2006     2005  
 
Recorded in operating costs and expenses
  $ 1,927     $ 707     $ 25     $ 2,511     $ 600  
Recorded in capital expenditures
    1,750       1               5,433       1,154  
                                         
Total
  $ 3,677     $ 708     $ 25     $ 7,944     $ 1,754  
                                         
 
We expect our net cash outlay for pipeline integrity program expenditures to approximate $2.7 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
 
  •  growth 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 nine months of 2006, our capital expenditures, including sustaining and growth capital expenditures, totaled $59.0 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 and Mont Belvieu brine production and above-ground storage projects will be approximately $42.7 million, of which our 66% share will be approximately $28.2 million. We expect to use cash on hand from the proceeds of this offering to fund our share of these planned expansion costs and Enterprise Products Partners will make a capital contribution to South Texas NGL and Mont Belvieu Caverns 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 new revolving 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 — Future Mont Belvieu Caverns Expansion Capital.”
 
New Revolving Credit Facility
 
We have entered into a new $300 million revolving credit facility, all of which may be used for letters of credit, with a $30 million sublimit for Swingline loans. The funding date of the revolving credit facility will occur not later than ninety days after the closing of this offering, at which point, we may make our initial drawing under the facility. The new revolving credit facility will mature four years from the funding date. We may make up to two requests for one-year extensions of the maturity date (subject to certain restrictions). The revolving credit facility will be available to pay distributions upon the initial contribution of assets to us, fund working capital, make acquisitions and provide payment for general partnership purposes. We can increase the revolving credit facility, without consent of the lenders, by an amount not exceeding $150 million by


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adding to the facility one or more new lenders and/or increasing the commitments of existing lenders. No lender will be required to increase its commitment, unless it agrees to do so in its sole discretion.
 
The revolving credit facility offers the following unsecured loans, each having different minimum amount and interest requirements:
 
  •  LIBOR loans.  LIBOR loans can be exercised in a minimum amount of $5 million and multiples of $1 million thereafter. No more than eight LIBOR borrowings may be outstanding at any time under the revolving credit facility. LIBOR loans will bear interest, at a rate per annum, equal to LIBOR plus the applicable LIBOR margin.
 
  •  Base Rate Loans.  Base Rate Loans can be exercised in a minimum amount of $1 million and multiples of $500 thousand thereafter. These loans bear interest, at a rate per annum, equal to the Base Rate plus zero. The Base Rate is the higher of (i) the rate of interest publicly announced by the administrative agent, Wachovia Bank, National Association, as its Base Rate and (ii) 0.5% per annum above the Federal Funds Rate in effect on such date.
 
  •  Swingline Loans.  Swingline loans can be exercised in a minimum amount of $1 million and multiples of $100 thousand thereafter. These loans bear interest at the LIBOR Market Interest Rate plus the applicable LIBOR margin.
 
The revolving credit facility may be prepaid in whole or in part at any time upon same day notice, in a minimum amount of $3 million with respect to LIBOR loans and $1 million with respect to Base Rate Loans (or any lesser amount equal to outstanding borrowings), and integral multiples of $1 million above that amount. Unless LIBOR loans are prepaid on interest payment dates, breakage costs could be incurred.
 
The revolving credit facility requires us to maintain a leverage ratio for the prior four fiscal quarters of not more than 4.75 to 1.00 at the last day of each fiscal quarter commencing June 30, 2007; provided, upon the closing of a permitted acquisition, such ratio shall not exceed (a) 5.25 to 1.00 at the last day of the fiscal quarter in which such specified acquisition occurred and at the last day of each of the two fiscal quarters following the fiscal quarter in which such specified acquisition occurred, and (b) 4.75 to 1.00 at the last day of each fiscal quarter thereafter. In addition, prior to obtaining an investment-grade rating by Standard & Poor’s Ratings Services, Moody’s Investors Service or Fitch Ratings, our interest coverage ratio, for the prior four fiscal quarters shall not be less than 2.75 to 1.00 at the last day of each fiscal quarter commencing June 30, 2007.
 
Our new revolving credit facility contains various operating and financial covenants, including those restricting or limiting our ability, and the ability of certain of our subsidiaries, to:
 
  •  make distributions;
 
  •  incur additional indebtedness;
 
  •  grant liens or make certain negative pledges;
 
  •  engage in certain asset conveyances, sales, leases, transfers, distributions or otherwise dispose of certain assets, businesses or operations;
 
  •  make certain investments;
 
  •  enter into a merger, consolidation, or dissolution;
 
  •  engage in transactions with affiliates;
 
  •  directly or indirectly make or permit any payment or distribution in respect of our partnership interests; or
 
  •  permit or incur any limitation on the ability of any of our subsidiaries to pay dividends or make distributions to, repay indebtedness to, or make subordinated loans or advances to us.


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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. Each of the following is an event of default under the new credit agreement:
 
  •  non-payment of any principal, interest or fees when due under the credit agreement subject to grace periods to be negotiated;
 
  •  non-performance of covenants subject to grace periods to be negotiated;
 
  •  failure of any representation or warranty to be true and correct in any material respect;
 
  •  failure to pay any other material debt exceeding $10 million in the aggregate;
 
  •  a change of control;
 
  •  other customary defaults, including specified bankruptcy or insolvency events, the Employee Retirement Income Security Act of 1974, or ERISA, violations, and judgment defaults.
 
Contractual Obligations
 
The following table summarizes our significant contractual obligations at December 31, 2005. There have been no material changes in the nature or amounts of such obligations subsequent to December 31, 2005 other than the capital expenditures related to South Texas NGL discussed below.
 
                                         
    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
  $ 1,518,016     $ 216,690     $ 433,973     $ 433,380     $ 433,973  
Other
  $ 7,480     $ 2,138     $ 4,282     $ 1,060          
Underlying major volume commitments:
                                       
Natural gas (in Bbtus)
    127,850       18,250       36,550       36,500       36,550  
Capital expenditure commitments
  $ 616     $ 616                          
Other long-term liabilities
  $ 608                             $ 608  
                                         
Total
  $ 1,530,529     $ 219,991     $ 439,350     $ 435,402     $ 435,786  
                                         
 
 
(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 revolving 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 revolving credit facility that are expected to be made under variable interest rates.


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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 and $0.9 million and $1.0 million for the nine months ended September 30, 2006 and 2005, respectively.
 
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. Enterprise Products Partners will contribute this pipeline system to South Texas NGL prior to the closing of this offering. This pipeline system is 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 $66.3 million. South Texas NGL made capital expenditures of $37.7 million to make this pipeline system operational in January 2007. We expect that it will cost approximately $28.6 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 $18.9 million. In addition, we expect that Mont Belvieu Caverns will make additional capital expenditures of $14.1 million to complete construction of brine production capacity and above-ground storage reservoirs, of which our 66%


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share will be approximately $9.3 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 September 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 nine 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.


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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 September 30, 2006 and December 31, 2005, the net book value of our property, plant and equipment was $656.0 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 $15.4 million and $14.2 million for the nine months ended September 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 periods presented.
 
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 periods presented.


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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 September 30, 2006 and December 31, 2005, the carrying value of our intangible asset portfolio was $7.0 million and $7.2 million, respectively. We recorded $0.2 million in amortization expense associated with our intangible assets for all periods presented.
 
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. For all periods presented, our revenue and cost estimates are substantially correct as compared to actual amounts.
 
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 September 30, 2006, our imbalance receivable was $1.9 million and our imbalance payable was $0.5 million.


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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 nine month period ended September 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 September 30, 2006, our storage imbalance was $1.8 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 $2.7 and $1.9 million for the nine months ended September 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 $2.5 million for the nine months ended September 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 $1.0 million charge and a $3.2 million charge for the nine months ended September 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


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


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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 Propylene and Lou-Tex Propylene 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. Prior to the closing of this offering, we will become party to a ground lease with Enterprise Products Partners as a result of an assignment by an affiliate of Enterprise Products Partners. 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 Propylene and Sabine Propylene 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 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 OLP pursuant to which Enterprise Products OLP 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 and Mont Belvieu Caverns brine-related facilities. In addition, we will grant Enterprise Products OLP a right of first refusal on the equity interests in certain of our operating subsidiaries and on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business.
 
  •  TEPPCO Partners.  During January 2007, an affiliate of Enterprise Products Partners purchased from an affiliate of TEPPCO Partners a 10-mile, 18-inch segment of pipeline that forms part of the South Texas NGL pipeline for an aggregate purchase price of $8 million. This pipeline will be among the assets owned by South Texas NGL at the closing of this offering. We have also entered into a lease with TEPPCO Partners for a 12-mile, 10-inch interconnecting pipeline extending from Pasadena, Texas to Baytown, Texas. The primary term of this lease will expire on September 15, 2007, and will continue on a month-to-month basis subject to termination by either party upon 60 days’ notice. This pipeline is being leased by us in connection with operations on our South Texas NGL pipeline until we complete the construction of a parallel pipeline.
 
  •  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.


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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. We believe that our operating subsidiaries will be subject to the Texas Margin Tax on the portion of their revenues generated in Texas. 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


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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 September 30, 2006 and December 31, 2005 and 2004. The fair value of our commodity financial instrument portfolio was a negligible amount at September 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 gain related to our commodity financial instruments during the nine months ended September 30, 2006. We recorded $0.2 million of expense related to this portfolio during the nine months ended September 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.


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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 consists 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 became operational and began transporting NGLs in January 2007 after undergoing modifications, extensions and interconnections. Additional expansions to this system are scheduled to be completed during the remainder of 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


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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 26.4% 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.


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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 56% 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 22.4 Tcf per year, with average annual domestic production of approximately 18.9 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 18.5 Tcf per year to 20.4 Tcf per year between 2004 and 2015.
 
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.
 
FLOW CHART
 
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


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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.


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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


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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.
 
LEFT
 
During 2005 and 2006, we constructed additional brine production capacity and above-ground storage reservoirs at Mont Belvieu. These projects are expected to be completed during the first quarter of 2007. We will retain $9.3 million from the proceeds of this offering to fund our 66% share of estimated capital expenditures to complete these projects. Through December 31, 2006, we recorded total capital expenditures of $71.5 million related to these projects.
 
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 38% of our total storage revenues for the nine months ended September 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 34% of our total storage revenues for the nine months ended September 30, 2006.


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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 reserve 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
 
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 nine months ended September 30, 2006 and 2005, we recorded $14.8 million and $13.9 million, respectively, 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 against Mont Belvieu Storage Partners, L.P., Targa Resources, Texas Brine and ONEOK in the Gulf Coast region. The principal competitive factors affecting our product storage business are storage fees, quantity and location of pipeline connections and operational dependability. We believe that the fees we charge our customers are competitive with those charged by other storage operators because we have historically been able to renew existing contracts as they mature, yielding many long-standing relationships. We are distinguished from our competitors by the location and quantity of our pipeline connections. The number of pipeline connections gives us flexibility to offer a wide variety of receipt and delivery options to customers and meet their requests on an efficient basis. Our pipeline connections to the petrochemical plants, NGL fractionators and imports from the Houston ship channel allow us to effectively compete in this business because these are the services required by our customers. In addition, we differentiate ourselves through our emphasis on operational dependability that consists of a focus on maintaining our facilities.
 
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


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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 estimated 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 new revolving 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 — Future Mont Belvieu Caverns Expansion Capital.”
 
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.


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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 38% and 62%, respectively, of the average daily gas


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volumes for the first nine 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
    Nine Months
 
    December 31,     Ended
 
    2003     2004     2005     September 30, 2006  
 
Gas Sales Volumes
    331       330       317       345  
Transportation Volume
    269       315       323       428  
                                 
Total System Volume
    600       645       640       773  
 
Customers
 
The Acadian Gas system transported approximately 773 Bbtu/d of natural gas to its customers during the first nine 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 expired on December 1, 2006, but the parties entered into an amendment to extend the term until November 2009. During the nine months ended September 30, 2006, ExxonMobil shipped approximately 143 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.


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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 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


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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 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


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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.
 
Competition
 
Our Acadian Gas system competes with several onshore natural gas pipelines in the South Louisiana market on the basis of price (in terms of transportation fees or natural gas selling prices), location, service, reliability and flexibility. The transportation fees and natural gas sales prices we charge our customers are competitive with those charged by other onshore pipelines in the area because we rely on certain published indices for our pricing. We are distinguished from our competitors within the onshore South Louisiana market because of our long-standing customer relationships. Due to the limited number of alternative delivery pipeline connections to those customers, we have been able to retain our customers for many years. Our competitors have the ability to connect into various customers on our pipeline but at a higher cost due to new pipelines and other related facilities. It is critical to the customers in the region that we provide reliable service to enable our customers flexibility of supply through the many connections to our system. Because of our location and long-standing presence in South Louisiana, we are able to compete effectively in this market.
 
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 Propylene 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 Propylene 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 Propylene pipeline was constructed in 1997 and acquired by Enterprise Products Partners in March 2000 from an affiliate of Shell.
 
  •  Sabine Propylene Pipeline.  The Sabine Propylene 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


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  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 Propylene pipeline. Shell is the only customer that uses the Sabine Propylene pipeline.
 
Contracts.  Enterprise Products Partners has entered into separate product exchange agreements with Shell and ExxonMobil involving the use of our Sabine Propylene and Lou-Tex Propylene 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 Propylene and Sabine Propylene pipelines. The term of the Lou-Tex Propylene 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 Propylene 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 Propylene pipeline. Shell is obligated to meet minimum delivery requirements under the Lou-Tex Propylene and Sabine Propylene 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 Propylene pipeline. The term of the Lou-Tex Propylene 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 Propylene and Sabine Propylene pipelines with Shell and ExxonMobil to us concurrently with the closing of this offering. Prior to 2004, the Sabine Propylene pipeline was regulated by the FERC. The Lou-Tex Propylene pipeline was also subject to the FERC’s jurisdiction until 2005. For the periods in which the Sabine Propylene pipeline and the Lou-Tex Propylene 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.


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Throughput
 
The following table summarizes throughput of each of our petrochemical pipelines for the periods indicated:
 
Throughput (Bbls/d)(1)
 
                                         
        Years Ended
  Nine Months
        December 31,   Ended
    Capacity
  2003
  2004
  2005
  September 30, 2006
    (Bbls/d)   Total   Total   Total   Total
 
Lou-Tex Propylene Pipeline
    52,500       28,883       27,810       23,066       26,076  
Sabine Propylene Pipeline
    20,600       11,265       11,336       10,394       9,990  
 
 
(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 in the Gulf Coast market. Our petrochemical transportation competitors have varying levels of financial and personnel resources, and competition generally revolves around price, service, logistics and location. We differentiate ourselves from the larger oil and petrochemical companies primarily through the location of our pipelines and dedication of our pipelines to a single product service. Our petrochemical pipelines are in single product service due to the required purity of the product being shipped. Because there are no other pipelines in our market area which ship the same single product, we are able to compete against our larger competitors for this service. In the future, a competitor could change service of an existing pipeline to ship single products, but they would have to incur additional costs to connect to our customers.
 
NGL Pipeline Services Segment
 
General
 
Our NGL Pipeline Services segment consists 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 Belvieu, Texas. The South Texas NGL pipeline system became operational and began transporting NGLs in January 2007 after undergoing modifications, extensions and interconnections 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. Currently, the capacity of the 223-mile pipeline we purchased from ExxonMobil Pipeline Company is approximately 100,000 Bbls/d and expandable to 175,000 Bbls/d. During Phase I:
 
(1) we will construct approximately 13 miles of pipeline and utilize an existing 32-mile pipeline to complete pipeline laterals to connect the two fractionation facilities to the 223-mile segment of our South Texas NGL pipeline system; and
 
(2) we have entered into a lease with TEPPCO Partners for a 12-mile, 10-inch interconnecting pipeline extending from Pasadena, Texas to Baytown, Texas. The primary term of the pipeline lease will expire on September 15, 2007, and will continue on a month-to-month basis subject to termination by either party upon 60 days’ notice.


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During January 2007, an affiliate of Enterprise Products Partners acquired an additional 10-mile, 18-inch segment of pipeline from an affiliate of TEPPCO Partners, which connects the leased TEPPCO pipeline to Mont Belvieu, Texas. The purchase of the 10-mile segment of 18-inch pipeline from TEPPCO Partners was for an aggregate purchase price of $8 million. This pipeline will be among the assets owned by South Texas NGL at the closing of this offering.
 
During Phase II, we will construct 21 miles of 18-inch pipeline to replace the leased 12-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 is 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. We have entered into a ten-year transportation contract with Enterprise Products Partners that includes 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 no less than $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 no less than $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 will 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.
 
  •  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


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  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 (nine months ended September 30)
  65,884
 
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.
 
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


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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 September 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 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


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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 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 Propylene 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.


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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.
 
Some of the leases, easements, rights-of-way, permits and licenses to be transferred to us require the consent of the grantor of such rights. Our general partner expects to obtain, prior to the closing of this offering, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects as described in this prospectus. With respect to any material consents, permits or authorizations that have not been obtained prior to closing of this offering, the closing of this offering will not occur unless reasonable basis exist that permit our general partner to conclude that such consents, permits or authorizations will be obtained within a reasonable period following the closing, or the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business.
 
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.


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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 William A. Bruckmann, III, Larry J. Casey and Joe D. Havens are “independent” under the NYSE rules.
 
Heightened Independence for Audit, Conflicts and Governance 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, Conflicts and Governance 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, Conflicts and Governance 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.


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  •  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. The Presiding Director will be the Chairman of the Audit, Conflicts and Governance 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, Conflicts and Governance 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 877-888-0002. 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
 
After giving effect to this offering, the Board of Directors of our general partner will have one committee, the Audit, Conflicts and Governance Committee, which we refer to in this prospectus as the ACG Committee.
 
Audit, Conflicts and Governance 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 ACG Committee. The mem