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Index to Financial Statements

As Filed with the Securities and Exchange Commission on July 21, 2005

Registration No. 333-124320


SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549


Amendment No. 2

to

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933


Enterprise GP Holdings L.P.

(Exact Name of Registrant as Specified in Its Charter)


Delaware   4922   13-4297064

(State or Other Jurisdiction of

Incorporation or Organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification No.)


Enterprise GP Holdings L.P.

2727 North Loop West, Suite 101

Houston, Texas 77008-1044

(713) 426-4500

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)


Richard H. Bachmann

2727 North Loop West, Suite 101

Houston, Texas 77008-1044

(713) 426-4500

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


Copies to:

Michael P. Finch

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2300

Houston, Texas 77002

(713) 758-2222

 

Robert V. Jewell

Andrews Kurth LLP

600 Travis, Suite 4200

Houston, Texas 77002

(713) 220-4200


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.   ¨

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.   ¨

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.   ¨

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.   ¨

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.   ¨


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 this 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. We may not sell these securities 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 is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

Subject to Completion, dated July 21, 2005

 

P R O S P E C T U S

 

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12,000,000 Units

Representing Limited Partner Interests

 


 

We are offering 12,000,000 units, including $51 million of units to an affiliate of our ultimate parent company, EPCO, Inc., for contribution to a partnership established for the benefit of certain employees of EPCO and $10 million of units to entities controlled by Dan L. Duncan, the Chairman of our general partner and EPCO. This is the initial public offering of our units. We expect the initial public offering price to be between $26.00 and $28.00 per unit. We are the sole member of Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners L.P., a publicly traded partnership. Enterprise Products Partners is a North American energy company providing a wide range of services to producers and consumers of natural gas, natural gas liquids and crude oil. We intend to list our units on the New York Stock Exchange under the symbol “EPE.”

 

We will use all of the net proceeds from this offering to repay amounts outstanding under a new credit facility which we will enter into concurrently with the closing of this offering. Affiliates of certain underwriters in this offering, including Citigroup and Lehman Brothers, will be lenders under our new credit facility. See “Use of Proceeds” and “Underwriting.”

 

Investing in our units involves risk. See “ Risk Factors ” beginning on page 19.

 

These risks include the following:

 

    Initially, our operating cash flow will be derived primarily from cash distributions from Enterprise Products Partners.

 

    Our unitholders do not elect our general partner or vote on our general partner’s officers or directors. Following the completion of this offering, affiliates of our general partner will own sufficient units to block any attempt to remove our general partner.

 

    You will experience immediate and substantial dilution of $20.07 per unit.

 

    Conflicts of interest exist and may arise among us, our general partner, Enterprise Products Partners and any existing or future affiliated entities.

 

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

 

    Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

 

     Per Unit

   Total

Initial Public Offering Price

   $                 $             

Underwriting Discount(1)

   $      $  

Proceeds to Enterprise GP Holdings L.P. (before expenses)

   $      $  

(1) The underwriters will not receive any underwriting discount or commission on any sale of the (i) $61 million of units offered to entities controlled by Dan L. Duncan (representing 2,259,259 units at an assumed offering price of $27.00) and (ii) $5 million of units offered to O.S. Andras, a director of Enterprise Products GP, LLC (representing 185,185 units at the assumed offering price). Accordingly, proceeds to us (before expenses) include the full per unit initial public offering price of these units. See “Underwriting.”

 

We have granted the underwriters a 30-day option to purchase up to an additional 1,516,667 units on the same terms and conditions as set forth above if the underwriters sell more than 12,000,000 units.

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

The underwriters expect to deliver the units on or about                         , 2005.

 


 

Citigroup   Lehman Brothers

 

                    , 2005


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TABLE OF CONTENTS

 

SUMMARY

   1

Enterprise GP Holdings L.P.

   1

The Offering

   6

Our Management

   7

Enterprise Products Partners L.P.

   7

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

   8

Summary of Certain Risk Factors

   11

Summary Historical and Pro Forma Financial and Operating Data

   12

Non-GAAP Financial Measures

   16

RISK FACTORS

   19

Risks Inherent in an Investment in Us

   19

Risks Related to Conflicts of Interest

   24

Risks Related to Enterprise Products Partners’ Business

   27

Tax Risks to Our Unitholders

   34

USE OF PROCEEDS

   37

CAPITALIZATION

   38

DILUTION

   40

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

   41

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

   58

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

   63

Overview

   63

Recent Developments

   64

Results of Operations

   68

Liquidity and Capital Resources

   81

Enterprise GP Holdings

   81

Enterprise Products Partners

   81

Cash Flows from Operating, Investing and Financing Activities

   84

Debt Obligations

   88

Enterprise GP Holdings

   88

Enterprise Products Partners

   89

Capital Spending

   96

Recent Accounting Developments

   102

Critical Accounting Policies

   103

Enterprise Products Partners’ Related Party Transactions

   107

Other Items

   109

Quantitative and Qualitative Disclosures about Market Risk

   111

BUSINESS OF ENTERPRISE GP HOLDINGS

   118

General

   118

Our Business Strategy

   121

How Our Partnership Agreement Terms Differ from those of Other Publicly Traded Partnerships

   121

BUSINESS OF ENTERPRISE PRODUCTS PARTNERS

   122

General

   122

Business Strategy

   122

Enterprise Products Partners’ Operations

   122

Offshore Pipelines & Services

   123

Onshore Natural Gas Pipelines & Services

   131

 

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NGL Pipelines & Services

   137

Petrochemical Services

   150

Employees

   155

Major Customers

   156

Regulation and Environmental Matters

   156

Environmental Matters

   160

Title to Properties

   162

Legal Proceedings

   162

MANAGEMENT

   163

General

   163

Governance Matters

   163

Enterprise GP Holdings

   166

Long-Term Incentive Plan

   168

Enterprise Products Partners

   169

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

   177

Enterprise GP Holdings

   177

Enterprise Products Partners

   177

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

   180

Our Relationship with EPCO, Enterprise Products GP and Enterprise Products Partners

   180

Related Party Transactions of Enterprise Products GP

   180

Related Party Transactions of Enterprise Products Partners

   181

Administrative Services Agreement

   184

Indemnification of Directors and Officers

   186

CONFLICTS OF INTEREST AND BUSINESS OPPORTUNITY AGREEMENTS; FIDUCIARY DUTIES

   187

Conflicts of Interest and Business Opportunity Agreements

   187

Fiduciary Duties

   191

DESCRIPTION OF OUR UNITS

   194

Transfer Agent and Registrar

   194

Transfer of Units

   194

DESCRIPTION OF OUR PARTNERSHIP AGREEMENT

   195

Organization and Duration

   195

Purpose

   195

Power of Attorney

   195

Capital Contributions

   195

Limited Liability

   195

Voting Rights

   196

Issuance of Additional Securities

   197

Amendments to Our Partnership Agreement

   198

Merger, Sale or Other Disposition of Assets

   199

Termination or Dissolution

   200

Liquidation and Distribution of Proceeds

   200

Withdrawal or Removal of Our General Partner

   201

Transfer of General Partner Interest

   202

Transfer of Ownership Interests in Our General Partner

   202

Change of Management Provisions

   202

Limited Call Right

   202

Meetings; Voting

   203

Status as Limited Partner

   203

Non-Citizen Assignees; Redemption

   203

Indemnification

   204

 

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Reimbursement of Expenses

   204

Books and Reports

   204

Right to Inspect Our Books and Records

   205

Registration Rights

   205

ENTERPRISE PRODUCTS PARTNERS’ CASH DISTRIBUTION POLICY

   206

Distributions of Available Cash

   206

Operating Surplus and Capital Surplus

   206

Distributions of Available Cash from Operating Surplus

   207

Incentive Distributions

   207

Distributions from Capital Surplus

   207

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

   208

Distributions of Cash upon Liquidation

   208

MATERIAL PROVISIONS OF ENTERPRISE PRODUCTS PARTNERS’ PARTNERSHIP AGREEMENT

   210

Purpose

   210

Voting Rights

   210

Issuance of Additional Securities

   210

Amendments to Enterprise Products Partners’ Partnership Agreement

   211

Merger, Sale or Other Disposition of Assets

   212

Termination or Dissolution

   212

Liquidation and Distribution of Proceeds

   213

Withdrawal or Removal of Enterprise Products Partners’ General Partner

   213

Transfer of General Partner Interests

   214

Change of Management Provisions

   214

Limited Call Right

   215

Reimbursement of Expenses

   215

Indemnification

   215

Registration Rights

   215

UNITS ELIGIBLE FOR FUTURE SALE

   216

MATERIAL TAX CONSEQUENCES

   217

Partnership Status

   217

Limited Partner Status

   219

Tax Consequences of Unit Ownership

   219

Tax Treatment of Operations

   224

Disposition of Units

   224

Uniformity of Units

   226

Tax-Exempt Organizations and Other Investors

   227

Administrative Matters

   228

State, Local, Foreign and Other Tax Considerations

   229

INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS

   231

UNDERWRITING

   232

VALIDITY OF THE UNITS

   235

EXPERTS

   235

FORWARD-LOOKING STATEMENTS

   236

WHERE YOU CAN FIND MORE INFORMATION

   237

INDEX TO FINANCIAL STATEMENTS

   F-1

APPENDIX A—Form of Amended and Restated Agreement of Limited Partnership of Enterprise GP Holdings L.P.

   A-1

 

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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 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 as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.

 

No representation or warranty, express or implied, is made by the underwriters as to accuracy or completeness of the information contained in this prospectus, and nothing in this prospectus is, or should be relied upon as, a promise or representation by the underwriters. In addition, the underwriters do not provide any tax advice.

 

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SUMMARY

 

This summary highlights information from this prospectus to help you understand our units. You should read carefully the entire prospectus and the other documents to which we refer for a more complete understanding of this offering. You should read “Risk Factors” beginning on page 19 of this prospectus for more information about important risks that you should consider before making a decision to purchase units in this offering.

 

Unless otherwise stated, the information presented in this prospectus assumes that the underwriters do not exercise their option to purchase additional units and assumes an initial public offering price of $27.00 per unit. All references in this prospectus to “we,” “us,” “Enterprise GP Holdings” and “our” refer to Enterprise GP Holdings L.P. All references in this prospectus to “our general partner” refer to EPE Holdings, LLC. All references in this prospectus to “Enterprise Products Partners” refer to Enterprise Products Partners L.P. and its consolidated subsidiaries. All references in this prospectus to “Enterprise Products GP” refer to Enterprise Products GP, LLC, the general partner of Enterprise Products Partners. All references to “EPCO” refer to EPCO, Inc., our ultimate parent company, and its affiliates, unless the context indicates otherwise. All references in this prospectus to Enterprise Products Partners’ number of units, earnings per unit or unit price give effect to Enterprise Products Partners’ two-for-one unit split on May 15, 2002. The descriptions in this prospectus of our partnership interests in Enterprise Products Partners give effect to the contribution by EPCO of those interests to us in connection with the closing of this offering. We will enter into a new $525 million credit facility concurrently with the closing of this offering, which we refer to in this prospectus as our “new credit facility.”

 

Enterprise GP Holdings L.P.

 

We are the sole member of Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners L.P., a publicly traded partnership. Enterprise Products Partners is a North American energy company providing a wide range of processing, storage and transportation services (commonly referred to as midstream services) to producers and consumers of natural gas, natural gas liquids and crude oil, and an industry leader in the development of pipeline and other midstream assets in the continental United States and deepwater Gulf of Mexico.

 

Our assets consist of the following partnership interests in Enterprise Products Partners contributed to us by EPCO:

 

    a 100% ownership of Enterprise Products GP, which owns a 2% general partner interest in Enterprise Products Partners that entitles us to receive 2% of the cash distributed by Enterprise Products Partners;

 

    the incentive distribution rights associated with Enterprise Products Partners’ general partner interest, which entitle us to receive increasing percentages of the cash distributed by Enterprise Products Partners (up to a maximum of 25%) as Enterprise Products Partners’ per unit distribution increases; and

 

    13,454,498 common units of Enterprise Products Partners, representing an approximate 3.4% limited partner interest in Enterprise Products Partners.

 

Because the incentive distribution rights currently participate at the maximum 25% sharing level (inclusive of the 2% general partner interest) in all distributions made by Enterprise Products Partners above $0.3085 per unit, future growth in distributions we receive from Enterprise Products Partners will not result from an increase in the sharing level associated with the incentive distribution rights. Please read “Enterprise Products Partners’ Cash Distribution Policy—Incentive Distributions.”

 

Since its initial public offering in 1998, Enterprise Products Partners has increased its quarterly distribution by approximately 87%, from $0.225 per unit, or $0.90 per unit on an annualized basis, to $0.42 per unit, or $1.68 per unit on an annualized basis. Based upon Enterprise Products Partners’ recently announced quarterly distribution of $0.42 per unit declared and payable with respect to the second quarter of 2005 and the number of its common units

 

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outstanding at July 15, 2005, we would have been entitled to receive a quarterly cash distribution of approximately $25.7 million (or approximately $102.8 million on an annualized basis), consisting of $3.3 million from Enterprise Products GP’s 2% general partner interest, $16.7 million from the associated incentive distribution rights and $5.7 million from the common units of Enterprise Products Partners that we own.

 

The graph set forth below shows the historical cash distributions declared and paid or payable during the periods shown with respect to our partnership interests in Enterprise Products Partners. From 2000 through 2004, the aggregate annual cash distributions declared and paid by Enterprise Products Partners in respect of all of its partnership interests increased 209%, from approximately $141.0 million to approximately $435.8 million. Over the same period, the aggregate annual cash distributions declared and paid by Enterprise Products Partners in respect of our partnership interests increased 258%, from $17.0 million, or 12.1% of Enterprise Products Partners’ aggregate annual distributions, to $60.8 million, or 14.0% of Enterprise Products Partners’ aggregate annual distributions. The increase in historical cash distributions on our partnership interests reflected in the graph set forth below generally resulted from the following:

 

    the increase in Enterprise Products Partners’ per unit quarterly distribution from $0.25 declared and paid in the first quarter of 2000 to $0.42 declared and payable in the third quarter of 2005; and

 

    the issuance of approximately 250 million additional units by Enterprise Products Partners during such period to finance acquisitions and capital improvements.

 

 

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The graph set forth below shows hypothetical cash distributions payable in respect of our partnership interests in Enterprise Products Partners across an illustrative range of annualized distributions per unit made by Enterprise Products Partners. This information is based upon the following assumptions:

 

    Enterprise Products Partners’ 384,695,836 common units outstanding as of July 15, 2005; and

 

    our ownership of (i) a 2% general partner interest in Enterprise Products Partners, (ii) the associated incentive distribution rights and (iii) 13,454,498 common units of Enterprise Products Partners.

 

The following graph illustrates the impact to us of Enterprise Products Partners raising or lowering its per unit distribution from its recently announced quarterly distribution of $0.42 per unit, or $1.68 per unit on an annualized basis. This information is presented for illustrative purposes only and is not intended to be a prediction of future performance. In addition, it does not give effect to any potential future issuances of units by Enterprise Products Partners.

 

 

LOGO

 

Based upon Enterprise Products Partners’ current quarterly distribution and partners’ capitalization and our anticipated expenses, we expect that our initial quarterly distribution will be $0.25 per unit, or $1.00 per unit on an annualized basis. Please read “Our Cash Distribution Policy and Restrictions on Distributions.” Enterprise Products Partners’ cash distributions to us will vary depending on several factors, including Enterprise Products Partners’ outstanding partnership interests on the record date for the distribution, the per unit distribution and our relative ownership of such partnership interests. If Enterprise Products Partners increases or decreases distributions to us, we would expect to increase or decrease distributions to our unitholders accordingly, although the timing and amount of such changes in distributions, if any, will not necessarily be comparable to the timing and amount of any changes in distributions made by Enterprise Products Partners. In addition, the level of distributions we receive may be affected by the various risks associated with an investment in us and the underlying business of Enterprise Products Partners. Please read “Risk Factors.”

 

On or about November 18, 2005, we will pay a prorated quarterly distribution (based on our initial quarterly distribution of $0.25 per unit) for the period between the consummation of our initial public offering and September 30, 2005. However, we cannot assure you that any distributions will be declared or paid. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

 

 

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Our Business Strategy

 

Our primary objective is to increase our cash available for distributions to our unitholders and, accordingly, the value of the limited partner interests in our partnership. In recent years, major independent oil and gas and other energy companies have divested significant midstream assets. Additionally, there have been several transactions involving the sale of general partner interests in publicly traded partnerships. We believe that asset rationalization among energy companies and transactions involving the sale of such general partner interests will continue. Our business strategy to capitalize on these trends is to:

 

    manage Enterprise Products Partners for the successful execution of its business strategy;

 

    pursue acquisitions of assets and businesses that may or may not be related to Enterprise Products Partners’ business in accordance with our business opportunity agreements; and

 

    acquire general partner interests and associated incentive distribution rights and limited partner interests in other publicly traded partnerships.

 

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

 

The Transactions

 

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

 

    EPCO and its affiliates will contribute to us (i) an aggregate 100% membership interest in Enterprise Products GP and (ii) 13,454,498 common units in Enterprise Products Partners, and we will assume $159.6 million in indebtedness associated with certain of these assets;

 

    In connection with the contribution of these assets and the assumption by us of the debt, affiliates of EPCO will receive partnership interests in us which will be converted into an aggregate 74,667,332 units;

 

    We will enter into a new $525 million credit facility which will be used to repay (i) $159.6 million owed to EPCO and (ii) $365.4 million owed by Enterprise Products GP to Dan Duncan LLC;

 

    We will sell 12,000,000 units in this offering and use the net proceeds therefrom to repay a portion of our indebtedness outstanding under our new $525 million credit facility; and

 

    We will enter into an amended and restated administrative services agreement with EPCO and certain of its affiliates that will govern our relationship with them, including conflicts of interest, management and administrative services and the reimbursement thereof.

 

Employee Partnership

 

Prior to the closing of this offering, EPCO Holdings Inc., a wholly owned subsidiary of EPCO, will form a Delaware limited partnership, EPE Unit L.P., which we refer to as the employee partnership. EPCO Holdings will serve as the general partner of the employee partnership. In connection with the closing of this offering, EPCO Holdings will borrow $51 million to purchase an estimated 1,888,889 units from us at the initial public offering price. EPCO Holdings will contribute the purchased units, but not the related debt, to the employee partnership. In connection with the closing of this offering, certain EPCO employees, including all of our general partner’s executive officers other than our Chairman, Dan L. Duncan, will be issued limited partner interests without any capital contribution and admitted as limited partners of the employee partnership. EPCO Holdings will not be reimbursed, through the administrative services agreement or otherwise, for any expenses related to the employee partnership or to the purchase of the units to be contributed to the employee partnership. For additional information about this employee partnership, please read “Management—Enterprise GP Holdings—Executive Officer Compensation—Employee Partnership.”

 

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Our Structure

 

We were formed in April 2005. The chart below depicts our and our affiliates’ simplified organizational and ownership structure after giving effect to this offering (and based on the ownership of Enterprise Products Partners at July 15, 2005).

 

LOGO

 

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The Offering

 

Units offered

12,000,000 units, including 2,259,259 units offered to entities controlled by Dan L. Duncan; or 13,516,667 units if the underwriters exercise their option to purchase additional units in full.

 

Units outstanding after this offering

86,667,332 units; or 88,183,999 units if the underwriters exercise their option to purchase additional units in full.

 

Use of proceeds

We will use all of the net proceeds from this offering to repay approximately $305 million of indebtedness outstanding under our new credit facility, which we will enter into concurrently with the closing of this offering. Affiliates of Citigroup and Lehman Brothers, will be lenders under our new credit facility and will be repaid with the net proceeds of this offering. Please read “Use of Proceeds” and “Underwriting.”

 

Limited call right

If at any time our general partner and its affiliates own more than 90% of our outstanding units, our general partner has the right, but not the obligation, to purchase all of the remaining units at a price not less than the then-current market price of the units.

 

Limited voting rights

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 66  2 / 3 % of the outstanding units, including units owned by our general partner and its affiliates, voting together as a single class. Upon completion of this offering, affiliates of our general partner will own sufficient units to block any attempt to remove our general partner. Please read “Description 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 units you purchase in this offering through December 31, 2008, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 10% of the cash distributed with respect to that period. Please read “Material Tax Consequences” in this prospectus for the basis of this estimate.

 

New York Stock Exchange listing

We intend to list our units on the New York Stock Exchange under the symbol “EPE.”

 

How Our Partnership Agreement Differs

Our limited partnership agreement differs from those of many publicly traded partnerships. For example, our general partner’s 0.01% general partner interest in us is fixed without any required capital contribution in connection with the issuance of additional units by us. In addition, we do not have subordinated units and our general partner is not entitled to incentive distributions. Please read “Description of Our Units” and “Description of Our Partnership Agreement.”

 

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Our Management

 

Our general partner will manage our operations and activities. All of the executive officers and non-independent directors of our general partner also serve as executive officers or directors of Enterprise Products 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. We and our general partner will enter into an amended and restated administrative services agreement with EPCO and affiliated parties in connection with the closing of this offering, pursuant to which EPCO will provide all employees and administrative, operational and other services for us. Pursuant to the amended and restated administrative services agreement, EPCO will be reimbursed by us at cost for all services provided to us. Please read “Certain Relationships and Related Party Transactions—Administrative Services Agreement.”

 

Our principal executive offices are located at 2727 North Loop West, Suite 101, Houston, Texas 77008, and our telephone number is (713) 426-4500. Our website is located at http://www.enterprisegp.com . Information on our website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

 

Enterprise Products Partners L.P.

 

Enterprise Products Partners is a leading North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, natural gas liquids and crude oil and is an industry leader in the development of pipeline and other midstream assets in the continental United States and deepwater Gulf of Mexico. Enterprise Products Partners operates an integrated midstream asset base within the United States.

 

Enterprise Products Partners has four reportable business segments that are generally organized and managed along its midstream asset base according to the type of services rendered (or technology employed) and products produced and sold. For a description of each segment’s results of operations and revenues, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” For a description of each segment’s assets and operations, please read “Business of Enterprise Products Partners—Enterprise Products Partners’ Operations.”

 

Enterprise Products Partners’ business strategy is to:

 

    capitalize on expected increases in natural gas, natural gas liquids and oil production resulting from development activities in the deepwater and continental shelf areas of the Gulf of Mexico and in the Rocky Mountain region;

 

    maintain a balanced and diversified portfolio of midstream energy assets and expand this asset base through organic development projects and accretive acquisitions of complementary midstream energy assets;

 

    share capital costs and risks through joint ventures or alliances with strategic partners that will provide the raw materials for these projects or purchase the projects’ end products; and

 

    increase fee-based cash flows by investing in pipelines and other fee-based businesses and de-emphasize commodity-based activities.

 

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

 

Acquisitions of Competing Businesses. From time to time, we or our affiliates may acquire entities whose businesses compete with us or Enterprise Products Partners. For example, in February 2005, an affiliate of EPCO acquired all of the membership interests of Texas Eastern Products Pipeline Company, LLC, which owns a 2% general partner interest in and is the general partner of TEPPCO Partners, L.P., which we refer to as TEPPCO Partners. In a related transaction, an affiliate of EPCO acquired 2.5 million common units of TEPPCO Partners. Purchasers of units in this offering will not benefit from the cash generated by TEPPCO Partners and its subsidiaries. Please read “Risk Factors—Enterprise Products Partners could be required to divest significant assets as a result of a non-public investigation by the Bureau of Competition of the Federal Trade Commission.”

 

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

 

Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our partners. All of the executive officers and non-independent directors of our general partner also serve as executive officers or directors of Enterprise Products GP and, as a result, have fiduciary duties to manage the business of Enterprise Products Partners in a manner beneficial to Enterprise Products Partners and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to Enterprise Products Partners, on the one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders. For a more detailed description of the conflicts of interest involving our general partner, please read “Conflicts of Interest and Business Opportunity Agreements; Fiduciary Duties.”

 

Potential Future Conflicts . Future conflicts of interest may arise among us and any entities whose general partner interests we or our affiliates acquire or among Enterprise Products Partners, TEPPCO Partners and such entities. It is not possible to predict the nature or extent of these potential future conflicts of interest at this time, nor is it possible to determine how we will address and resolve any such future conflicts of interest. However, the resolution of these conflicts may not always be in our best interest or that of our unitholders. We do not currently intend to take any action which would limit the ability of Enterprise Products Partners to pursue its business strategy.

 

Administrative Services Agreement. EPCO, Enterprise Products Partners, Enterprise Products GP and certain affiliated entities are parties to an administrative services agreement, effective as of October 1, 2004. As amended to date, this administrative services agreement provides, among other things, that if the EPCO Group, which includes EPCO and its affiliates (excluding Enterprise Products Partners, Enterprise Products GP and Enterprise Products Operating L.P. and certain affiliated parties, which excluded parties we refer to as partnership entities, and also excluding TEPPCO Partners, its general partner and their controlled affiliates), is offered by a third party, or discovers an opportunity to acquire from a third party, a business or assets that is or are in the same or similar line of business then being conducted by a partnership entity or in a line of business that would be a natural extension of any business then being conducted by a partnership entity, which we refer to as a business opportunity, the EPCO Group must promptly advise the board of directors of Enterprise Products GP of such business opportunity and offer such business opportunity to Enterprise Products Partners. If the board of directors of Enterprise Products GP does not advise the EPCO Group within ten days following the receipt of

 

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Index to Financial Statements

such notice that Enterprise Products Partners wishes to pursue such business opportunity, the EPCO Group will be permitted to pursue such business opportunity. If the board of directors of Enterprise Products GP advises the EPCO Group within such ten-day period that Enterprise Products Partners wishes to pursue such business opportunity, the EPCO Group will not be permitted to pursue such business opportunity unless the board of directors of Enterprise Products GP subsequently advises the EPCO Group that Enterprise Products Partners has abandoned its pursuit of such business opportunity.

 

In connection with the closing of this offering, the administrative services agreement will be amended and restated to address potential conflicts that may arise among us, Enterprise Products Partners, Enterprise Products GP and the EPCO Group. The amended and restated administrative services agreement will provide, among other things, that:

 

    if a business opportunity to acquire 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, our general partner, Enterprise Products GP or Enterprise Products Partners, we will have the first right to pursue the acquisition. In the event that we abandon the acquisition and so notify the EPCO Group and Enterprise Products Partners, Enterprise Products Partners will have the second right to pursue such acquisition. Enterprise Products Partners will be presumed to desire to acquire the equity securities until such time as it advises the EPCO Group that it has abandoned the pursuit of such acquisition. In the event that Enterprise Products Partners abandons the acquisition and so notifies the EPCO Group, the EPCO Group may pursue the acquisition without any further obligation to any other party or offer such opportunity to other affiliates.

 

    if any business opportunity not covered by the preceding bullet point is presented to the EPCO Group, us, our general partner, Enterprise Products GP or Enterprise Products Partners, Enterprise Products Partners will have the first right to pursue such opportunity. In the event that Enterprise Products Partners abandons the business opportunity and so notifies the EPCO Group and us, we will have the second right to the pursue such opportunity. We will be presumed to desire to pursue the business opportunity until such time as we advise the EPCO Group that we have abandoned the pursuit of such business opportunity. In the event that we abandon the business opportunity and so notify the EPCO Group, the EPCO Group may pursue the business opportunity without any further obligation to any other party or offer such opportunity to other affiliates.

 

None of the EPCO Group, we, our general partner, Enterprise Products GP or Enterprise Products Partners 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, our general partner, Enterprise Products GP or Enterprise Products Partners. For a more detailed description of these provisions, please read “Certain Relationships and Related Party Transactions—Administrative Services Agreement.”

 

Shared Personnel. Our general partner will manage our operations and activities. Under the amended and restated administrative services agreement, EPCO will provide all employees and administrative, 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, TEPPCO Partners and their affiliates. The services performed by these shared personnel will generally be limited to non-commercial functions, including but not limited to human resources, information technology, financial and accounting services and legal services. We will adopt policies and procedures to protect and prevent inappropriate disclosure by shared personnel of commercial and other non-public information relating to us, Enterprise Products Partners and TEPPCO Partners.

 

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Index to Financial Statements

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

 

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

 

Fiduciary Duties . Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner 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 fiduciary duty owed to unitholders. By purchasing our 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 and Business Opportunity Agreements; 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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Index to Financial Statements

Summary of Certain Risk Factors

 

An investment in our units involves risks associated with us and Enterprise Products Partners and the tax characteristics associated with interests in publicly traded partnerships. You should consider carefully all the risk factors together with all of the other information included in this prospectus before you invest in our units. The risks related to an investment in us, conflicts of interest, Enterprise Products Partners’ business and tax consequences to our unitholders are described under the caption “Risk Factors.” Certain risks include:

 

Risks Inherent in an Investment in Us

 

    Initially, our operating cash flow will be derived primarily from cash distributions from Enterprise Products Partners.

 

    In the future, we may not have sufficient cash to pay distributions at our estimated initial quarterly distribution level or to increase distributions.

 

    Our unitholders do not elect our general partner or vote on our general partner’s officers or directors. Following the completion of this offering, affiliates of our general partner will own sufficient units to block any attempt to remove our general partner.

 

    You will experience immediate and substantial dilution of $20.07 per unit.

 

    We may issue an unlimited number of limited partner interests without the consent of our unitholders, which will dilute your ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.

 

Risks Related to Conflicts of Interest

 

    Conflicts of interest exist and may arise among us, Enterprise Products Partners, TEPPCO Partners and our respective general partners and affiliates or entities affiliated with general partner interests that we may acquire in the future.

 

    If we are presented with certain business opportunities, Enterprise Products Partners will have the first right to pursue such opportunities.

 

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

 

Risks Related to Enterprise Products Partners’ Business

 

    Changes in the prices of hydrocarbon products may materially adversely affect Enterprise Products Partners’ results of operations, cash flows and financial condition.

 

    A decline in the volume of natural gas, NGLs and crude oil delivered to Enterprise Products Partners’ facilities could materially adversely affect its results of operations, cash flows and financial condition.

 

    A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect Enterprise Products Partners’ results of operations, cash flows and financial position.

 

Tax Risks to Our Unitholders

 

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

 

    A successful IRS contest of the federal income tax positions taken by Enterprise Products Partners may adversely impact the market for its units, and the costs of any contest will be borne by Enterprise Products Partners, and therefore indirectly by us and the other unitholders.

 

    Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

 

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Index to Financial Statements

Summary Historical and Pro Forma Financial and Operating Data

 

We were formed in April 2005 and therefore do not have any historical financial statements for 2004. As a result of being under common control with Enterprise Products GP, our unaudited pro forma condensed consolidated financial information incorporates the condensed consolidated financial information of Enterprise Products GP, which includes Enterprise Products Partners’ financial information.

 

The following tables set forth, for the periods and at the dates indicated, summary historical consolidated financial and operating data for Enterprise Products GP and our summary pro forma consolidated financial data. The summary historical statement of consolidated operations data for the years ended December 31, 2004, 2003 and 2002 and consolidated balance sheet data at December 31, 2004 and 2003 should be read in conjunction with the audited financial statements of Enterprise Products GP included elsewhere in this prospectus. The summary historical statement of consolidated operations data for the three months ended March 31, 2005 and 2004 and consolidated balance sheet data at March 31, 2005 should be read in conjunction with the unaudited financial statements of Enterprise Products GP included elsewhere in this prospectus.

 

Our summary unaudited pro forma financial information gives effect to the following transactions:

 

    the completion by Enterprise Products Partners of its merger with GulfTerra Energy Partners, L.P., or GulfTerra, and the related transactions and financings;

 

    the use of proceeds from the sale of 17,250,000 common units by Enterprise Products Partners in each of May 2004, August 2004 and February 2005 and from the issuance of 1,926,810 common units by Enterprise Products Partners in connection with its distribution reinvestment plan, or DRIP, and related programs during the first six months of 2005;

 

    the issuance by Enterprise Products Partners’ operating partnership of $500 million of senior unsecured notes in each of March 2005 and June 2005 and the related use of proceeds;

 

    the assumption by us of $159.6 million of debt from an affiliate of EPCO in connection with the contribution to us by that affiliate of 13,454,498 Enterprise Products Partners common units and a 9.9% member interest in Enterprise Products GP; and

 

    the borrowing of $525.0 million by us under our new credit facility and the subsequent repayment by us of (i) $159.6 million to EPCO and (ii) $365.4 million owed by Enterprise Products GP to Dan Duncan LLC.

 

Our pro forma as adjusted financial information gives effect to the sale of 12,000,000 units in this offering and the application of the net proceeds to repay a portion of the indebtedness outstanding under our new credit facility as described under “Use of Proceeds.”

 

The unaudited pro forma condensed statements of consolidated operations for the three months ended March 31, 2005 and for the year ended December 31, 2004 assumes the pro forma transactions occurred on January 1, 2004 (to the extent not already reflected in the historical statements of consolidated operations of each entity). The unaudited pro forma condensed consolidated balance sheet shows the financial effects of the pro forma transactions as if they had occurred on March 31, 2005 (to the extent not already recorded in the historical balance sheet data of Enterprise Products GP).

 

 

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Index to Financial Statements

The following tables present summary historical consolidated financial and operating data of Enterprise Products GP and pro forma consolidated financial information for us for the periods indicated (dollars in thousands, except per unit amounts).

 

    

Consolidated Historical for

Enterprise Products GP


    Enterprise GP Holdings

 
     For the Year Ended December 31,

   

For the Year Ended

December 31, 2004


 
     2002

    2003

    2004

    Pro
Forma


   

Pro Forma

As Adjusted


 

Statement of Consolidated Operations Data: (1)

                                        

Revenues

   $ 3,584,783     $ 5,346,431     $ 8,321,202     $ 9,615,119     $ 9,615,119  

Costs and expenses:

                                        

Operating costs and expenses

     3,382,839       5,046,777       7,904,336       8,971,209       8,971,209  

General and administrative expenses

     44,109       39,164       47,264       96,766       96,766  
    


 


 


 


 


Total costs and expenses

     3,426,948       5,085,941       7,951,600       9,067,975       9,067,975  
    


 


 


 


 


Equity in income (loss) of unconsolidated affiliates

     35,253       (13,960 )     52,787       24,830       24,830  
    


 


 


 


 


Operating income

     193,088       246,530       422,389       571,974       571,974  

Other income (expense):

                                        

Interest expense

     (101,580 )     (140,806 )     (161,589 )     (266,792 )     (248,491 )

Dividend income from unconsolidated affiliates

     4,737       5,595                          

Loss due to early redemption of debt

                             (16,285 )     (16,285 )

Other, net

     2,696       914       2,130       3,802       3,802  
    


 


 


 


 


Total

     (94,147 )     (134,297 )     (159,459 )     (279,275 )     (260,974 )

Income before income taxes, minority interest and changes in accounting principles

     98,941       112,233       262,930       292,699       311,000  

Provision for income taxes

     (1,634 )     (5,293 )     (3,761 )     (3,761 )     (3,761 )
    


 


 


 


 


Income before minority interest and changes in accounting principles

     97,307       106,940       259,169       288,938       307,239  

Minority interest (2)

     (86,805 )     (86,783 )     (228,716 )     (272,688 )     (272,688 )
    


 


 


 


 


Income from continuing operations

     10,502       20,157       30,453     $ 16,250     $ 34,551  
                            


 


Cumulative effect of changes in accounting principles

                     216                  
    


 


 


               

Net income

   $ 10,502     $ 20,157     $ 30,669                  
    


 


 


               

Earnings per unit, basic and diluted

                           $ 0.22     $ 0.40  
                            


 


Consolidated Balance Sheet Data (at period end) (1) :

                                        

Total assets

   $ 4,235,494     $ 4,802,802     $ 11,315,901                  

Total debt (3)

     2,246,463       2,139,548       4,647,669                  

Combined equity (4)

     25,966       36,443       164,883                  

Other Financial Data (1) :

                                        

Cash flows provided by operating activities

     326,256       421,606       376,068                  

Cash flows used in investing activities

     (1,708,348 )     (656,976 )     (1,299,119 )                

Cash flows provided by financing activities

     1,265,712       247,556       917,591                  

Distributions received from unconsolidated affiliates

     57,662       31,882       68,027                  

Equity in (income) loss from unconsolidated affiliates

     (35,253 )     13,960       (52,787 )                

Gross operating margin

   $ 332,349     $ 410,415     $ 655,191     $ 1,047,513     $ 1,047,513  

EBITDA

   $ 199,822     $ 282,057     $ 391,403     $ 675,422     $ 675,422  

Operating Data (1) :

                                        

Offshore Pipelines & Services, net:

                                        

Natural gas transportation volumes (BBtus/d)

     500       433       2,081                  

Crude oil transportation volumes (MBbls/d)

                     138                  

Platform gas treating (BBtus/d)

                     306                  

Platform oil treating (MBbls/d)

                     14                  

Onshore Natural Gas Pipelines & Services, net:

                                        

Natural gas transportation volumes (BBtus/d)

     701       600       5,638                  

NGL Pipelines & Services, net:

                                        

Natural gas liquids transportation volumes (MBbls/d)

     1,306       1,275       1,411                  

Natural gas liquids fractionation volumes (MBbls/d)

     235       227       307                  

Equity Natural gas liquids production (MBbls/d)

     73       43       129                  

Fee-based natural gas processing volumes (MMcf/d)

             194       1,692                  

Petrochemical Services, net:

                                        

Butane isomerization volumes (MBbls/d)

     84       77       76                  

Propylene fractionation volumes (MBbls/d)

     55       57       56                  

Octane additive production volumes (MBbls/d)

     5       4       10                  

Petrochemical transportation volumes (MBbls/d)

     46       68       71                  

 

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Index to Financial Statements
     Consolidated Historical for
Enterprise Products GP


     Enterprise GP Holdings

 
    

For the Three Months

Ended March 31,


    

For the Three Months

Ended March 31, 2005


 
     2004

     2005

     Pro Forma

    

Pro Forma

As Adjusted


 

Statement of Consolidated Operations Data: (1)

                                   

Revenues

   $ 1,704,890      $ 2,555,522      $ 2,555,522      $ 2,555,522  

Costs and expenses:

                                   

Operating costs and expenses

     1,621,508        2,383,644        2,389,202        2,389,202  

General and administrative expenses

     9,498        15,153        15,903        15,903  
    


  


  


  


Total costs and expenses

     1,631,006        2,398,797        2,405,105        2,405,105  
    


  


  


  


Equity in income of unconsolidated affiliates

     14,867        8,279        7,966        7,966  
    


  


  


  


Operating income

     88,751        165,004        158,383        158,383  

Other income (expense):

                                   

Interest expense

     (32,618 )      (59,052 )      (59,704 )      (55,191 )

Other, net

     165        924        924        924  
    


  


  


  


Total

     (32,453 )      (58,128 )      (58,780 )      (54,267 )

Income before income taxes, minority interest and changes in accounting principles

     56,298        106,876        99,603        104,116  

Provision for income taxes

     (1,625 )      (1,769 )      (1,769 )      (1,769 )
    


  


  


  


Income before minority interest and changes in accounting principles

     54,673        105,107        97,834        102,347  

Minority interest (2)

     (43,608 )      (95,664 )      (88,144 )      (88,144 )
    


  


  


  


Income from continuing operations

     11,065        9,443      $ 9,690      $ 14,203  
                      


  


Cumulative effect of changes in accounting principles

     216                             
    


  


                 

Net income

   $ 11,281      $ 9,443                    
    


  


                 

Earnings per unit, basic and diluted

                     $ 0.13      $ 0.16  
                      


  


Consolidated Balance Sheet Data (at period end) (1) :

                                   

Total assets

            $ 11,527,765      $ 11,737,335      $ 11,737,335  

Total debt (3)

              4,522,712        4,881,473        4,576,453  

Combined equity (4)

              171,908        323,684        628,704  

Other Financial Data (1) :

                                   

Cash flows provided by operating activities

     29,409        174,040                    

Cash flows used in investing activities

     (15,811 )      (364,992 )                  

Cash flows provided by financing activities

     1,048        223,720                    

Distributions received from unconsolidated affiliates

     16,932        21,838                    

Equity in income from unconsolidated affiliates

     (14,867 )      (8,279 )                  

Gross operating margin

   $ 131,141      $ 275,214      $ 269,343      $ 269,343  

EBITDA

   $ 76,109      $ 172,151      $ 173,050      $ 173,050  

Operating Data (1) :

                                   

Offshore Pipelines & Services, net:

                                   

Natural gas transportation volumes (BBtus/d)

     429        1,851                    

Crude oil transportation volumes (MBbls/d)

              121                    

Platform gas treating (BBtus/d)

              316                    

Platform oil treating (MBbls/d)

              8                    

Onshore Natural Gas Pipelines & Services, net:

                                   

Natural gas transportation volumes (BBtus/d)

     646        5,746                    

NGL Pipelines & Services, net:

                                   

Natural gas liquids transportation volumes (MBbls/d)

     1,368        1,394                    

Natural gas liquids fractionation volumes (MBbls/d)

     229        338                    

Equity Natural gas liquids production (MBbls/d)

     48        100                    

Fee-based natural gas processing volumes (MMcf/d)

     362        2,018                    

Petrochemical Services, net:

                                   

Butane isomerization volumes (MBbls/d)

     60        66                    

Propylene fractionation volumes (MBbls/d)

     54        67                    

Octane additive production volumes (MBbls/d)

     5                             

Petrochemical transportation volumes (MBbls/d)

     63        74                    

 

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Index to Financial Statements

The non-generally accepted accounting principle, or 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 and pro forma financial data for Enterprise Products GP and us. Please read “—Non-GAAP Financial Measures” for explanations and reconciliations of the non-GAAP financial measures presented on the following page.

 

The following information is provided to highlight significant trends and other information regarding Enterprise Products GP’s historical operating results, financial position and other financial data. Each section below represents a footnote to the tables on the two previous pages.

 

(1) In general, Enterprise Products GP’s historical consolidated operating results and financial position have been affected by numerous acquisitions since 2000. Enterprise Products Partners’ most significant transaction to date was the GulfTerra merger and related transactions. The aggregate value of total consideration paid or issued by Enterprise Products Partners to complete the GulfTerra merger was approximately $4 billion. The operating results of these acquired entities are included in Enterprise Products GP’s consolidated financial results prospectively from their respective purchase dates.

 

(2) Minority interest represents ownership interests of third-party joint venture partners and non-affiliates of Enterprise Products GP and related party ownership interests of EPCO and its controlled affiliates in the net assets and earnings of certain subsidiaries of Enterprise GP Holdings. The primary group of minority interest holders reflected in the historical financial information of Enterprise Products GP consists of the third-party and related party owners of the limited partner interests of Enterprise Products Partners. Minority interest in Enterprise Products GP’s consolidated earnings and net assets has increased over time as a result of equity offerings and merger-related issuances of limited partner interests in Enterprise Products Partners. Please read Note 10, “Minority Interest,” of the Notes to Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

(3) In general, the consolidated debt of Enterprise Products GP has increased over time as a result of Enterprise Products Partners financing all or a portion of its business combinations and other acquisition-related activity.

 

(4) Members’ equity of Enterprise Products GP increased in 2004 as a result of contributions related to the GulfTerra merger.

 

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

 

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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 financial measures to their most directly comparable financial measure or measures calculated and presented in accordance with GAAP.

 

Gross operating margin . We evaluate the performance of Enterprise Products Partners’ business segments based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of Enterprise Products Partners’ consolidated operations. This measure forms the basis of Enterprise Products Partners’ 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 Enterprise Products Partners’ management uses in evaluating segment results. The GAAP measure most directly comparable to total segment gross operating margin is operating income. Enterprise Products Partners’ non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

 

Enterprise Products Partners defines total (or consolidated) segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which it does not have the payment obligation; (3) gains and losses on the sale of assets; and (4) 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 intercompany transactions.

 

Enterprise Products Partners has historically included equity earnings from unconsolidated affiliates in its measurement of segment gross operating margin and operating income. Enterprise Products Partners’ equity investments with industry partners are a vital component of its business strategy. They are a means by which Enterprise Products Partners conducts its operations to align its interests with those of its customers, which may be suppliers of raw materials or consumers of finished products. This method of operation also enables Enterprise Products Partners to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what it could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to its other business operations.

 

Enterprise Products Partners’ integrated midstream energy asset system (including the midstream energy assets of its equity method investees) provides services to producers and consumers of natural gas, natural gas liquids and petrochemicals. Enterprise Products Partners’ asset system has multiple entry points. In general, hydrocarbons can enter its asset system through a number of ways, including an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, a natural gas liquids gathering pipeline, a natural gas liquids fractionator, a natural gas liquids storage facility, a natural gas liquids transportation or distribution pipeline or an onshore natural gas pipeline. At each link along this asset system, Enterprise Products Partners earns revenues based on volume through the provision of services or through the ownership and sale of products such as natural gas liquids.

 

Many of Enterprise Products Partners’ equity investees are present within its integrated midstream asset system. For example, Enterprise Products Partners has ownership interests in several offshore natural gas and crude oil pipelines through its investments in Poseidon Oil Pipeline Company, L.L.C., Cameron Highway Oil Pipeline Company, Deepwater Gateway, L.L.C., Neptune Pipeline Company and Nemo Gathering Company, L.L.C. Enterprise Products Partners also has a number of investments in natural gas liquids transportation or distribution pipelines such as those owned by Belle Rose NGL Pipeline LLC and Dixie Pipeline Company (prior

 

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Index to Financial Statements

to its purchasing consolidating interests in Dixie in January and February 2005). Other examples include Enterprise Products Partners’ use of the K/D/S Promix LLC, or Promix, natural gas liquids fractionator to process natural gas liquids extracted by its gas plants. The natural gas liquids received from Promix then can be sold in Enterprise Products Partners’ natural gas liquids marketing activities. Given the integral nature of its equity investees to its operations, Enterprise Products Partners believes that the presentation of earnings from its equity method investees as a component of gross operating margin and operating income is appropriate.

 

EBITDA . We define EBITDA as consolidated net income or loss plus interest expense, provision for income taxes and depreciation 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 consolidated assets without regard to financing methods, capital structures or historical cost basis; (2) the ability of our consolidated assets to generate cash sufficient to pay interest and support our indebtedness; (3) our consolidated 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 cash flow from operating activities.

 

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The following table presents (i) a reconciliation of the non-GAAP financial measure of gross operating margin to the GAAP financial measure of operating income and (ii) 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 historical financial information of Enterprise Products GP, Enterprise Products GP also reconciles EBITDA to its GAAP financial measure of cash provided by operating activities.

 

                                  Enterprise GP Holdings

 
    Historical Consolidated of Enterprise Products GP

    For the Year Ended
December 31, 2004


   

For the Three
Months Ended

March 31, 2005


 
    For the Year Ended
December 31,


   

For the Three
Months Ended

March 31,


   

Pro

Forma


   

Pro

Forma

As
Adjusted


   

Pro
Forma


    Pro
Forma
As
Adjusted


 
    2002

    2003

    2004

    2004

    2005

         

Reconciliation of Non-GAAP "Gross operating margin" to GAAP "Operating income"

                                                                       

Operating income

  $ 193,088     $ 246,530     $ 422,389     $ 88,751     $ 165,004     $ 571,974     $ 571,974     $ 158,383     $ 158,383  

Adjustments to reconcile Operating income to Gross operating margin:

                                                                       

Depreciation and amortization in operating costs and expenses

    86,028       115,643       193,734       30,520       99,965       386,969       386,969       99,965       99,965  

Retained lease expense, net in operating costs and expenses

    9,125       9,094       7,705       2,274       528       7,705       7,705       528       528  

Loss (gain) on sale of assets in operating costs and expenses

    (1 )     (16 )     (15,901 )     98       (5,436 )     (15,901 )     (15,901 )     (5,436 )     (5,436 )

General and administrative expenses

    44,109       39,164       47,264       9,498       15,153       96,766       96,766       15,903       15,903  
   


 


 


 


 


 


 


 


 


Total Gross Operating Margin

  $ 332,349     $ 410,415     $ 655,191     $ 131,141     $ 275,214     $ 1,047,513     $ 1,047,513     $ 269,343     $ 269,343  
   


 


 


 


 


 


 


 


 


Reconciliation of Non-GAAP "EBITDA" to GAAP "Net Income" and GAAP "Cash provided by operating activities"

                                                                       

Net income

  $ 10,502     $ 20,157     $ 30,669     $ 11,281     $ 9,443     $ 16,250     $ 34,551     $ 9,690     $ 14,203  

Adjustments to net income to derive EBITDA:

                                                                       

Interest expense (including related amortization)

    101,580       140,806       161,589       32,618       59,052       266,792       248,491       59,704       55,191  

Provision for income taxes

    1,634       5,293       3,761       1,625       1,769       3,761       3,761       1,769       1,769  

Depreciation and amortization (excluding amortization component of interest expense)

    86,106       115,801       195,384       30,585       101,887       388,619       388,619       101,887       101,887  
   


 


 


 


 


 


 


 


 


EBITDA

  $ 199,822     $ 282,057     $ 391,403     $ 76,109     $ 172,151     $ 675,422     $ 675,422     $ 173,050     $ 173,050  
   


 


 


 


 


 


 


 


 


Adjustments to EBITDA to derive cash provided by operating activities (add or subtract as indicated by sign of number):

                                                                       

Interest expense

    (101,580 )     (140,806 )     (161,589 )     (32,618 )     (59,052 )                                

Provision for income taxes

    (1,634 )     (5,293 )     (3,761 )     (1,625 )     (1,769 )                                

Cumulative effect of changes in accounting principles

                    (216 )     (216 )                                        

Equity in loss (income) of unconsolidated affiliates

    (35,253 )     13,960       (52,787 )     (14,867 )     (8,279 )                                

Amortization in interest expense

    8,819       12,634       3,503       798       (477 )                                

Deferred income tax expense

    2,080       10,534       9,608       1,687       1,802                                  

Provision for non-cash asset impairment charge

            1,200       4,114                                                  

Distributions received from unconsolidated affiliates

    57,662       31,882       68,027       16,932       21,838                                  

Operating lease expense paid by EPCO

    9,125       9,094       7,705       2,274       528                                  

Other expenses paid by EPCO

            443                                                          

Minority interest

    86,805       86,783       228,716       43,608       95,664                                  

Loss (gain) on sale of assets

    (1 )     (16 )     (15,901 )     98       (5,436 )                                

Changes in fair market value of financial instruments

    10,213       (29 )     5       3       102                                  

Decrease (increase) in restricted cash used for operating activities

    (2,999 )     (5,100 )     (12,305 )     5,825       15,799                                  

Net effect of changes in operating accounts

    93,197       124,263       (90,454 )     (68,599 )     (58,831 )                                
   


 


 


 


 


                               

Cash provided by operating activities

  $ 326,256     $ 421,606     $ 376,068     $ 29,409     $ 174,040                                  
   


 


 


 


 


                               

 

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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 consider carefully the risk factors included below, together with all of the other information included in this prospectus, when evaluating an investment in our units.

 

If any of these risks were to occur, our or Enterprise Products Partners’ business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our units could decline, and you could lose all or part of your investment.

 

Risks Inherent in an Investment in Us

 

Initially, our operating cash flow will be derived primarily from cash distributions from Enterprise Products Partners.

 

Initially, our operating cash flow is primarily dependent upon Enterprise Products Partners making distributions to its partners. The amount of cash that Enterprise Products Partners can distribute to its partners, including us, each quarter principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things, the:

 

    amount of hydrocarbons transported in its gathering and transmission pipelines;

 

    throughput volumes in its processing and treating operations;

 

    fees it charges and the margins it realizes for its services;

 

    price of natural gas;

 

    relationships among crude oil, natural gas and natural gas liquids, or NGL, prices;

 

    fluctuations in its working capital needs;

 

    level of its operating costs, including reimbursements to its general partner; and

 

    prevailing economic conditions.

 

In addition, the actual amount of cash Enterprise Products Partners will have available for distribution will depend on other factors, including:

 

    the level of sustaining capital expenditures it makes;

 

    the cost of any acquisitions;

 

    its debt service requirements and restrictions contained in its obligations for borrowed money; and

 

    the amount of cash reserves established by Enterprise Products GP for the proper conduct of Enterprise Products Partners’ business.

 

Because of these factors, Enterprise Products Partners may not have sufficient available cash each quarter to continue paying distributions at its recently announced level of $0.42 per unit. Furthermore, the amount of cash that Enterprise Products Partners has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items such as depreciation, amortization and provisions for asset impairments. As a result, Enterprise Products Partners may be able to make cash distributions during periods when it records losses and may not be able to make cash distributions during periods when it records net income. Please read “—Risks Related to Enterprise Products Partners’ Business” for a discussion of further risks affecting Enterprise Products Partners’ ability to generate distributable cash flow.

 

In the future, we may not have sufficient cash to pay distributions at our estimated initial quarterly distribution level or to increase distributions.

 

Because our primary source of operating cash flow will initially consist of cash distributions from Enterprise Products Partners, the amount of distributions we are able to make to our unitholders may fluctuate

 

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based on the level of distributions Enterprise Products Partners makes to its partners. We cannot assure you that Enterprise Products Partners will continue to make quarterly distributions at its recently announced level of $0.42 per unit or increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our unitholders if Enterprise Products Partners increases or decreases distributions to us, the timing and amount of such changes in distributions, if any, will not necessarily be comparable to the timing and amount of any changes in distributions made by Enterprise Products Partners to us. Factors such as capital contributions, debt service requirements, general, administrative and other expenses, reserves for future distributions and other cash reserves established by the board of directors of our general partner may affect the distributions we make to our unitholders. Prior to making any distributions to our unitholders, we will reimburse our general partner and its affiliates for all direct and indirect expenses incurred by them on our behalf. Our general partner has the sole discretion to determine the amount of these reimbursed expenses. The reimbursement of these expenses, in addition to the other factors listed above, could adversely affect the level of distributions we make to our unitholders. We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our estimated initial quarterly distribution of $0.25 per unit. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of our general partner.

 

Restrictions in our credit facility could limit our ability to make distributions to our unitholders.

 

Concurrently with the closing of this offering, we will enter into a new $525 million credit facility. This credit facility will contain covenants limiting our ability to take certain actions. This credit facility will also contain covenants requiring us to maintain certain financial ratios. We will be prohibited from making any distribution to our unitholders if such distribution would cause an event of default or otherwise violate a covenant under this credit facility. For more information about our credit facility, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Obligations—Enterprise GP Holdings.”

 

Our unitholders do not elect our general partner or vote on our general partner’s officers or directors. Following the completion of this offering, affiliates of our general partner will own a sufficient number of units to block any attempt to remove our general partner.

 

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders do not have the ability to elect our general partner or the officers or directors of our general partner. Dan L. Duncan, through his control of Dan Duncan LLC, the sole member of our general partner, controls our general partner and the election of all of the officers and directors of our general partner.

 

Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner may not be removed except upon the vote of the holders of at least 66  2 / 3 % of our outstanding units. Because affiliates of our general partner own more than one-third of our outstanding units, our general partner currently cannot be removed without the consent of such affiliates. As a result, the price at which our units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

 

You will experience immediate and substantial dilution of $20.07 per unit.

 

The assumed initial public offering price of $27.00 per unit exceeds our pro forma net tangible book value of $6.93 per unit after the offering. Based on these amounts, you will incur immediate and substantial dilution of $20.07 per unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost in accordance with GAAP and not at their fair value. Please read “Dilution.”

 

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We may issue an unlimited number of limited partner interests without the consent of our unitholders, which will dilute your ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per unit distribution level.

 

Our partnership agreement provides that we may issue an unlimited number of limited partner interests without the consent of our unitholders. Such units may be issued on the terms and conditions established in the sole discretion of our general partner. Any issuance of additional units would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect market price of, units outstanding prior to such issuance. The payment of distributions on these additional units may increase the risk that we will be unable to maintain or increase our anticipated initial quarterly distribution. Please read “Description of Our Partnership Agreement—Issuance of Additional Securities.”

 

The market price of our units could be adversely affected by sales of substantial amounts of our units in the public markets, including sales by our existing unitholders.

 

Sales by any of our existing unitholders of a substantial number of our units in the public markets following this offering, or the perception that such sales might occur, could have a material adverse effect on the price of our units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sale would be made in the public market or in a private placement, nor do we know what impact such potential or actual sales would have on our unit price in the future. Please read “Units Eligible for Future Sale.”

 

Risks arising in connection with the execution of our business strategy may adversely affect our ability to make or increase distributions and/or the market price of our units.

 

In addition to seeking to maximize distributions from Enterprise Products Partners, a principal focus of our business strategy includes acquiring general partner interests and associated incentive distribution rights and limited partner interests in publicly traded partnerships and, subject to our business opportunity agreements, acquiring assets and businesses that may or may not relate to Enterprise Products Partners’ business. However, we may not be able to grow through acquisitions if we are unable to identify attractive acquisition opportunities or acquire identified targets. In addition, increased competition for acquisition opportunities may increase our cost of making acquisitions or cause us to refrain from making acquisitions.

 

If we are able to make future acquisitions, we may not be successful in integrating our acquisitions into our existing or future assets and businesses. Risks related to our acquisition strategy include:

 

    the creation of conflicts of interest and competing fiduciary obligations that may inhibit our ability to grow or make additional acquisitions;

 

    additional or increased regulatory or compliance obligations, including financial reporting obligations;

 

    delays or unforeseen operational difficulties or diminished financial performance associated with the integration of new acquisitions, and the resulting delayed or diminished cash flows from such acquisitions;

 

    inefficiencies and complexities that may arise due to unfamiliarity with new assets, businesses or markets;

 

    conflicts with regard to the sharing of management responsibilities and allocation of time among overlapping officers, directors and other personnel;

 

    the inability to hire, train and retain qualified personnel to manage and operate our growing business; and

 

    the inability to obtain required financing for our existing business and new investment opportunities.

 

To the extent we pursue an acquisition that causes us to incur unexpected costs, or that fails to generate expected returns, our results of operations, cash flows and financial condition may be adversely affected, and our ability to make distributions and/or the market price of our units may be negatively impacted.

 

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Index to Financial Statements

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 in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of Dan Duncan LLC, as the sole member of our general partner, to sell or transfer all or part of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the directors and officers of our general partner and control the decisions made and actions taken by the board of directors and officers.

 

All of our units and the common units of Enterprise Products Partners that are owned by EPCO and its affiliates, other than Dan Duncan LLC and the trusts affiliated with Dan L. Duncan, will be pledged as security under a new EPCO credit facility. Upon an event of default under this credit facility, a change in control of us or Enterprise Products Partners could result.

 

All of our units and the common units of Enterprise Products Partners (other than the 13,454,498 common units we own) that are owned or controlled by EPCO and its affiliates, other than Dan Duncan LLC and the trusts affiliated with Dan L. Duncan, will be pledged as security under a credit facility to be entered into concurrently with the closing of this offering by EPCO Holdings Inc., a wholly owned subsidiary of EPCO. This credit facility will contain customary and other events of default relating to certain defaults of the borrower, us, Enterprise Products Partners and other EPCO affiliates. Upon an event of default, a change in control of us and Enterprise Products Partners could result. Please read “Security Ownership of Certain Beneficial Owners and Management—Enterprise GP Holdings.”

 

All of our assets will be pledged under our new credit facility.

 

Concurrently with the closing of this offering, we will enter into a new $525 million credit facility. The 13,454,498 common units of Enterprise Products Partners and the 100% membership interest in Enterprise Products GP that will be contributed to us in connection with the closing of this offering will be pledged as security under this credit facility. Our new credit facility will contain customary and other events of default. Upon an event of default, the lenders under our new credit facility could foreclose on our assets, which would have a material adverse effect on our business, financial condition and results of operations.

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

 

If at any time our general partner and its affiliates own more than 90% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering, affiliates of our general partner, including the employee partnership, will own approximately 88.8% of our units. Please read “Description of Our Partnership Agreement—Limited Call Right.”

 

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 each of our general partner and Enterprise Products GP. Mr. Duncan has been integral to the success of Enterprise Products Partners and EPCO 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 or Enterprise Products Partners’ senior management teams could have a material adverse effect on the business, financial condition and results of operations of us, Enterprise Products Partners and our affiliates.

 

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An increase in interest rates may cause the market price of our units to decline resulting in the loss of a portion of your investment in us.

 

As interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our units to decline. As a result, you may lose a portion of your investment in us.

 

Enterprise Products Partners may issue additional units, which may increase the risk that Enterprise Products Partners will not have sufficient available cash to maintain or increase its per unit distribution level.

 

Enterprise Products Partners has wide latitude to issue additional units on terms and conditions established by Enterprise Products GP. The payment of distributions on those additional units may increase the risk that Enterprise Products Partners will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders.

 

Your liability as a limited partner may not be limited, and our unitholders may have to repay distributions or make additional contributions to us under certain circumstances.

 

As a limited partner in a partnership organized under Delaware law, you could be held liable for our obligations to the same extent as a general partner if you participate in the “control” of our business. Our general partner generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions. Please read “Description of Our Partnership Agreement—Limited Liability.”

 

Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, neither we nor Enterprise Products Partners may make a distribution to our unitholders if the distribution would cause our or Enterprise Products Partners’ respective liabilities to exceed the fair value of our respective assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

If in the future we cease to manage and control Enterprise Products Partners through our direct or indirect ownership of Enterprise Products GP, we may be deemed to be an investment company under the Investment Company Act of 1940.

 

If we cease to manage and control Enterprise Products Partners and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Securities and Exchange Commission, or the Commission, or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

 

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The initial public offering price of our units may not be indicative of the market price of our units after this offering, and our unit price may be volatile.

 

Prior to this offering there has been no public market for our units. An active market for our units may not develop or may not be sustained after this offering. The initial public offering price of our units will be determined by negotiations between us and the underwriters, based on several factors that we discuss in the “Underwriting” section of this prospectus. This price may not be indicative of the market price for our units after this initial public offering. The market price of our units could be subject to significant fluctuations after this offering, and may decline below the initial public offering price. You may not be able to resell your units at or above the initial public offering price. Our unit price could be affected by a number of factors, including:

 

    Enterprise Products Partners’ operating and financial performance and prospects;

 

    quarterly variations in the rate of growth of our distributions per unit;

 

    changes in revenue or earnings estimates or publication of research reports by analysts; and

 

    sales of our units by our unitholders.

 

There is no existing market for our units, and a trading market that will provide you with adequate liquidity may not develop.

 

Prior to the offering, there has been no public market for our 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. Potential investors may be deterred from investing in our units for various reasons, including the very limited number of publicly traded entities whose assets consist almost exclusively of partnership interests in a publicly traded partnership. Additionally, the lack of liquidity may contribute to significant fluctuations in the market price of the units and limit the number of investors who are able to buy the units.

 

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

 

Our unitholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management. As a result, the price at which our units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

 

Risks Related to Conflicts of Interest

 

Conflicts of interest exist and may arise in the future among us, Enterprise Products Partners, TEPPCO Partners and our respective general partners and affiliates. Future conflicts of interest may arise among us and the entities represented by any general partner interests we acquire or among Enterprise Products Partners, TEPPCO Partners and such entities. For a further discussion of conflicts of interest that may arise, please read “Conflicts of Interest and Business Opportunity Agreements; Fiduciary Duties” and “Certain Relationships and Related Party Transactions—Administrative Services Agreement.”

 

Conflicts of interest exist and may arise among us, Enterprise Products Partners, TEPPCO Partners and our respective general partners and affiliates and entities affiliated with any general partner interests that we may acquire in the future.

 

Conflicts of interest exist and may arise in the future as a result of the relationships among us, Enterprise Products Partners, TEPPCO Partners and our respective general partners and affiliates. Our general partner is controlled by Dan Duncan LLC, of which Dan L. Duncan is the sole member. Accordingly, Mr. Duncan has the ability to elect, remove and replace the directors and officers of our general partner. Similarly, through his indirect control of the general partner of each of Enterprise Products Partners and TEPPCO Partners, Mr. Duncan

 

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has the ability to elect, remove and replace the directors and officers of the general partner of each of Enterprise Products Partners and TEPPCO Partners. The assets of Enterprise Products Partners and TEPPCO Partners overlap in certain areas, which may result in various conflicts of interest in the future.

 

Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, all of our general partner’s executive officers and non-independent directors also serve as executive officers or directors of Enterprise Products GP and, as a result, have fiduciary duties to manage the business of Enterprise Products Partners in a manner beneficial to Enterprise Products Partners and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to Enterprise Products Partners, on the one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders. For a more detailed description of the conflicts of interest involving our general partner, please read “Conflicts of Interest and Business Opportunity Agreements; Fiduciary Duties.”

 

Future conflicts of interest may arise among us and any entities whose general partner interests we or our affiliates acquire or among Enterprise Products Partners, TEPPCO Partners and such entities. 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.

 

If we are presented with certain business opportunities, Enterprise Products Partners will have the first right to pursue such opportunities.

 

Pursuant to the amended and restated administrative services agreement to be entered into in connection with the closing of this offering, we will agree to certain business opportunity arrangements to address potential conflicts that may arise among us, Enterprise Products Partners and the EPCO Group. If a business opportunity in respect of any assets other than equity securities, which we generally define to include general partner interests in publicly traded partnerships and similar interests and associated incentive distribution rights and limited partner interests or similar interests owned by the owner of such general partner or its affiliates, is presented to the EPCO Group, us, our general partner, Enterprise Products GP or Enterprise Products Partners, then Enterprise Products Partners will have the first right to acquire such assets. The amended and restated administrative services agreement will provide, among other things, that Enterprise Products Partners will be presumed to desire to acquire the assets until such time as it advises the EPCO Group and us that it has abandoned the pursuit of such business opportunity, and we may not pursue the acquisition of such assets prior to that time. These business opportunity arrangements will limit our ability to pursue acquisitions of assets that are not “equity securities.” Please read “Certain Relationships and Related Party Transactions—Administrative Services Agreement” and “Conflicts of Interest and Business Opportunity Agreements; Fiduciary Duties.”

 

Our general partner’s affiliates may compete with us.

 

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement and subject to certain business opportunity agreements, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Please read “Conflicts of Interest and Business Opportunity Agreements; Fiduciary Duties—Conflicts of Interest and Business Opportunity Agreements” and “Certain Relationships and Related Party Transactions—Administrative Services Agreement.”

 

Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us and our unitholders, which may permit them to favor their own interests to the detriment of us and our unitholders.

 

Following this offering, Dan L. Duncan, EPCO and their controlled affiliates, including the employee partnership, will own approximately 88.8% of our units, and Dan Duncan LLC will own 100% of our general

 

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partner. Dan Duncan serves as our general partner’s Chairman as well as the Chairman of Enterprise Products GP. Conflicts of interest may arise among our general partner and its affiliates, 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. These conflicts include, among others, the following:

 

    our general partner is allowed to take into account the interests of parties other than us, including EPCO, Enterprise Products GP, Enterprise Products Partners and their respective affiliates and any future general partners and limited partnerships acquired in the future in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

 

    our general partner has limited its liability and reduced its fiduciary duties under the partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

 

    our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;

 

    our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

 

    our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us;

 

    our general partner controls the enforcement of obligations owed to us by it and its affiliates; and

 

    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—Administrative Services Agreement” and “Conflicts of Interest and Business Opportunity Agreements; Fiduciary Duties.”

 

Our partnership agreement limits our general partner’s fiduciary duties to us and our unitholders and restricts the remedies available to our 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;

 

    provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decision is in our best interests;

 

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

 

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

 

In order to become a limited partner of our partnership, our unitholders are required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Business Opportunity Agreements; Fiduciary Duties—Fiduciary Duties.”

 

Enterprise Products GP controls Enterprise Products Partners and may influence cash distributed to us.

 

Although we are the sole member of Enterprise Products GP, our control over Enterprise Products GP’s actions is limited. The fiduciary duties owed by Enterprise Products GP to Enterprise Products Partners and its unitholders prevent us from influencing Enterprise Products GP to take any action that would benefit us to the detriment of Enterprise Products Partners or its unitholders. For example, Enterprise Products GP makes business determinations on behalf of Enterprise Products Partners that impact the amount of cash distributed by Enterprise Products Partners to its unitholders and to Enterprise Products GP, which in turn, affects the amount of cash distributions we receive from Enterprise Products Partners and Enterprise Partners GP and consequently, the amount of distributions we can pay to our unitholders.

 

All of our executive officers face conflicts in the allocation of their time to our business.

 

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

 

Risks Related to Enterprise Products Partners’ Business

 

Since our cash flow will initially consist exclusively of distributions from Enterprise Products Partners, risks to Enterprise Products Partners’ business are also risks to us. We have set forth below risks to Enterprise Products Partners’ business, the occurrence of which could negatively impact Enterprise Products Partners’ financial performance and decrease the amount of cash it is able to distribute to us, thereby impacting the amount of cash that we are able to distribute to our unitholders.

 

Changes in the prices of hydrocarbon products may materially adversely affect Enterprise Products Partners’ results of operations, cash flows and financial condition.

 

Enterprise Products Partners operates predominantly in the midstream energy sector which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. As such, its 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. Generally, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are impossible to control. These factors include:

 

    the level of domestic production;

 

    the availability of imported oil and natural gas;

 

    actions taken by foreign oil and natural gas producing nations;

 

    the availability of transportation systems with adequate capacity;

 

    the availability of competitive fuels;

 

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    fluctuating and seasonal demand for oil, natural gas and NGLs; and

 

    conservation and the extent of governmental regulation of production and the overall economic environment.

 

Enterprise Products Partners is exposed to natural gas and NGL commodity price risk under natural gas processing and gathering and NGL fractionation contracts that provide for its fees to be calculated based on a regional natural gas or NGL price index or to be paid in-kind by taking title to natural gas or NGLs. A decrease in natural gas and NGL prices can result in lower margins from these contracts, which may materially adversely affect Enterprise Products Partners’ results of operations, cash flows and financial position.

 

A decline in the volume of natural gas, NGLs and crude oil delivered to Enterprise Products Partners’ facilities could materially adversely affect its results of operations, cash flows and financial condition.

 

Enterprise Products Partners’ profitability could be materially impacted by a decline in the volume of natural gas, NGLs and crude oil transported, gathered or processed at its facilities. A material decrease in natural gas or crude oil production or crude oil refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and crude oil handled by its facilities.

 

The crude oil, natural gas and NGLs available to Enterprise Products Partners’ facilities will be derived from reserves produced from existing wells, which reserves naturally decline over time. To offset this natural decline, Enterprise Products Partners’ facilities will need access to additional reserves. Additionally, some of its facilities will be dependent on reserves that are expected to be produced from newly discovered properties that are currently being developed.

 

Exploration and development of new oil and natural gas reserves is capital intensive, particularly offshore in the Gulf of Mexico. Many economic and business factors are beyond Enterprise Products Partners’ control and can adversely affect the decision by producers to explore for and develop new reserves. These factors could include relatively low oil and natural gas prices, cost and availability of equipment, regulatory changes, capital budget limitations or the lack of available capital. For example, a sustained decline in the price of natural gas and crude oil could result in a decrease in natural gas and crude oil exploration and development activities in the regions where Enterprise Products Partners’ facilities are located. This could result in a decrease in volumes to its offshore platforms, natural gas processing plants, natural gas, crude oil and NGL pipelines, and NGL fractionators which would have a material adverse affect on its results from operations cash flows and financial position. Additional reserves, if discovered, may not be developed in the near future or at all.

 

A reduction in demand for NGL products by the petrochemical, refining or heating industries could materially adversely affect Enterprise Products Partners’ results of operations, cash flows and financial position.

 

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

 

Ethane . If natural gas prices increase significantly in relation to ethane prices, 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.

 

Propane . The demand for propane as a heating fuel is significantly affected by weather conditions. Unusually warm winters could cause the demand for propane to decline significantly and could cause a significant decline in the volumes of propane that the combined company transports.

 

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Isobutane . Any reduction in demand for motor gasoline additives may reduce demand for isobutane. During periods in which the difference in market prices between isobutane and normal butane is low or inventory values are high relative to current prices for normal butane or isobutane, its operating margin from selling isobutane could be reduced.

 

Propylene . Any downturn in the domestic or international economy could cause reduced demand for propylene, which could cause a reduction in the volumes of propylene that Enterprise Products Partners produces and expose its investment in inventories of propane/propylene mix to pricing risk due to requirements for short-term price discounts in the spot or short-term propylene markets.

 

Enterprise Products Partners’ future debt level may limit its future financial and operating flexibility.

 

As of March 31, 2005, Enterprise Products Partners had approximately $4.2 billion of consolidated debt outstanding. The amount of Enterprise Products Partners’ future debt could have significant effects on its operations, including, among other things:

 

    a significant portion of Enterprise Products Partners’ cash flow could be dedicated to the payment of principal and interest on its future debt and may not be available for other purposes, including the payment of distributions on common units and capital expenditures;

 

    credit rating agencies may view its debt level negatively;

 

    its ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited; and

 

    it may be at a competitive disadvantage relative to similar companies that have less debt.

 

Enterprise Products Partners’ public debt indentures currently do not limit the amount of future indebtedness that it can create, incur, assume or guarantee. Although its multi-year revolving credit facility restricts its ability to incur additional debt, any debt it may incur in compliance with these restrictions may still be substantial.

 

Each of Enterprise Products Partners’ indentures for its public debt and revolving credit facilities contains conventional financial covenants and other restrictions. A breach of any of these restrictions by Enterprise Products Partners could permit the lenders to declare all amounts outstanding under those debt agreements to be immediately due and payable and, in the case of the credit facilities, to terminate all commitments to extend further credit.

 

Enterprise Products Partners’ ability to access the capital markets to raise capital on favorable terms will be affected by its debt level, the amount of its debt maturing in the next several years and current maturities, and by adverse market conditions. Moreover, if the rating agencies were to downgrade Enterprise Products Partners’ credit rating, then Enterprise Products Partners could experience an increase in its borrowing costs, difficulty assessing capital markets or a reduction in the market price of its common units. Such a development could adversely affect its ability to obtain financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness. If Enterprise Products Partners is unable to access the capital markets on favorable terms in the future, it might be forced to seek extensions for some of its short-term securities or to refinance some of its debt obligations through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which Enterprise Products Partners might receive such extensions or additional bank credit, if at all, could be more onerous than those contained in existing debt agreements. Any such arrangements could, in turn, increase the risk that its leverage may adversely affect its future financial and operating flexibility and thereby impact its ability to pay cash distributions at expected rates.

 

Enterprise Products Partners may not be able to fully execute its growth strategy if it encounters illiquid capital markets or increased competition for investment opportunities.

 

Enterprise Products Partners’ strategy contemplates growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This

 

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strategy includes constructing and acquiring additional assets and businesses to enhance its ability to compete effectively and diversify its asset portfolio, thereby providing more stable cash flow. Enterprise Products Partners regularly considers and enters into discussions regarding, and is currently contemplating, potential joint ventures, stand alone projects or other transactions that it believes will present opportunities to realize synergies, expand its role in the energy infrastructure business and increase its market position.

 

Enterprise Products Partners may require substantial new capital to finance the future development and acquisition of assets and businesses. Any limitations on Enterprise Products Partners’ access to capital will impair its ability to execute this strategy. If the cost of such capital becomes too expensive, Enterprise Products Partners’ ability to develop or acquire accretive assets will be limited. Enterprise Products Partners may not be able to raise the necessary funds on satisfactory terms, if at all.

 

In addition, Enterprise Products Partners is experiencing increased competition for the types of assets and businesses it historically has purchased or acquired. Increased competition for a limited pool of assets could result in Enterprise Products Partners losing to other bidders more often or acquiring assets at less attractive prices. Either occurrence would limit Enterprise Products Partners’ ability to fully execute its growth strategy. Enterprise Products Partners’ inability to execute its growth strategy may materially adversely affect its ability to pay higher distributions in the future.

 

Enterprise Products Partners’ growth strategy may adversely affect its results of operations if it does not successfully integrate the businesses that it acquires or if it substantially increases its indebtedness and contingent liabilities to make acquisitions.

 

Enterprise Products Partners’ growth strategy includes making accretive acquisitions. As a result, from time to time, Enterprise Products Partners will evaluate and acquire assets and businesses that it believes complement its existing operations. Enterprise Products Partners may incur substantial expenses or encounter delays or other problems in connection with its growth strategy that could negatively impact its results of operations, cash flows and financial condition.

 

If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, depletion and amortization expenses. As a result, Enterprise Products Partners’ capitalization and results of operations may change significantly following an acquisition. A substantial increase in its indebtedness and contingent liabilities could have a material adverse effect on its business.

 

Enterprise Products Partners could be required to divest significant assets as a result of a non-public investigation by the Bureau of Competition of the Federal Trade Commission.

 

On February 24, 2005, an affiliate of EPCO, acquired Texas Eastern Products Pipeline Company, LLC, or TEPPCO GP, from Duke Energy Field Services, LLC. TEPPCO GP owns a 2% general partner interest in and is the general partner of TEPPCO Partners. On March 11, 2005, the Bureau of Competition of the Federal Trade Commission delivered written notice to the EPCO affiliate’s legal advisor that it was conducting a non-public investigation to determine whether such affiliate’s acquisition of TEPPCO GP may substantially lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with the EPCO affiliate’s purchase of TEPPCO GP. EPCO and its affiliates may receive similar inquiries from other regulatory authorities. We intend to cooperate fully with any such investigations and inquiries. In response to such FTC investigation or any inquiries EPCO and its affiliates may receive from other regulatory authorities, Enterprise Products Partners may be required to divest certain assets. In the event Enterprise Products Partners is required to divest significant assets, its cash distributions to us could be reduced, which in turn, could reduce the cash we are able to distribute to our unitholders.

 

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Enterprise Products Partners’ operating cash flows from its capital projects may not be immediate.

 

Enterprise Products Partners is engaged in several construction projects, involving existing and new facilities, for which significant capital has been expended, and its operating cash flow from a particular project may not increase until after their completion. For instance, if Enterprise Products Partners builds a new pipeline or platform or expands an existing facility, the design, construction, development and installation may occur over an extended period of time, and Enterprise Products Partners may not receive any material increase in operating cash flow from that project until after it is placed in service. If Enterprise Products Partners experiences unanticipated or extended delays in generating operating cash flow from these projects, it may be required to reduce or reprioritize its capital budget, sell non-core assets, access the capital markets or decrease distributions to unitholders in order to meet its capital requirements.

 

The interruption of distributions to Enterprise Products Partners from its subsidiaries and joint ventures may affect Enterprise Products Partners’ ability to satisfy its obligations and to make cash distributions to its partners, including us.

 

Enterprise Products Partners is a holding company with no business operations. Its only significant assets are the equity interests it owns in its subsidiaries and joint ventures. As a result, Enterprise Products Partners depends upon the earnings and cash flow of its subsidiaries and joint ventures and the distribution of that cash to it in order to meet its obligations and to allow it to make distributions to its partners, including us.

 

In addition, Enterprise Products Partners’ joint venture charter documents typically vest in its management committee sole discretion regarding the occurrence and amount of distributions. Some of the joint ventures in which Enterprise Products Partners participates have several credit agreements that contain various restrictive covenants. Among other things, those covenants may limit or restrict the joint venture’s ability to make distributions to Enterprise Products Partners under certain circumstances. Accordingly, Enterprise Products Partners’ joint ventures may be unable to make distributions to it at current levels or at all.

 

Enterprise Products Partners’ actual construction and development costs could exceed forecasted amounts.

 

Enterprise Products Partners will have significant expenditures for the development and construction of energy infrastructure assets, including some construction and development projects with significant technological challenges. For example, underwater operations, especially those in water depths in excess of 3,000 feet, are very expensive and involve much more uncertainty and risk than those in more shallow depth, and if a problem occurs, the solution, if one exists, may be very expensive and time consuming. Enterprise Products Partners may not be able to complete its projects, whether in deepwater or otherwise, at the costs estimated at the time of each project’s initiation.

 

Enterprise Products Partners may be unable to cause its joint ventures to take or not to take certain actions unless some or all of its joint venture participants agree.

 

Enterprise Products Partners participates in several joint ventures. Due to the nature of some of these joint ventures, each participant in these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant organizational documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features customarily include a corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business, among others. Thus, without the concurrence of joint venture participants with enough voting interests, Enterprise Products Partners may be

 

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unable to cause any of its joint ventures to take or not to take certain actions, even though those actions may be in the best interest of us or the particular joint venture.

 

Moreover, any joint venture owner may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint venture owners. Any such transaction could result in Enterprise Products Partners being required to partner with different or additional parties.

 

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

 

Some of Enterprise Products Partners’ operations involve risks of personal injury, property damage and environmental damage, which could curtail its operations and otherwise materially adversely affect its cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Enterprise Products Partners also operates oil and natural gas facilities located underwater in the Gulf of Mexico, which can involve complexities, such as extreme water pressure. Virtually all of its operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.

 

If one or more facilities that are owned by Enterprise Products Partners or that deliver oil, natural gas or other products to Enterprise Products Partners are damaged by severe weather or any other disaster, accident, catastrophe or event, its operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply its facilities or other stoppages arising from factors beyond its 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. Additionally, some of the storage contracts to which Enterprise Products Partners is a party obligate it to indemnify its customers for any damage or injury occurring during the period in which the customers’ product is in its possession. Any event that interrupts the revenues generated by its operations, or which causes it to make significant expenditures not covered by insurance, could reduce Enterprise Products Partners’ cash available for paying its distributions and, accordingly, adversely affect the market price of its common units and adversely affect the market price of our units.

 

We believe that EPCO maintains adequate insurance coverage on behalf of Enterprise Products Partners, although insurance will not cover many types of interruptions that might occur. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, EPCO may not be able to renew existing insurance policies on behalf of Enterprise Products Partners or procure other desirable insurance on commercially reasonable terms, if at all. If Enterprise Products Partners were to incur a significant liability for which it 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.

 

An impairment of goodwill and intangible assets could reduce Enterprise Products Partners’ earnings.

 

At March 31, 2005, Enterprise Products Partners’ balance sheet reflected $456.7 million of goodwill and $960.1 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires Enterprise Products Partners to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If Enterprise Products Partners determines that any of its goodwill or intangible assets were impaired, it would be required to take an immediate charge to earnings with a correlative effect on partners’ equity and balance sheet leverage as measured by debt to total capitalization.

 

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Increases in interest rates could adversely affect Enterprise Products Partners’ business.

 

In addition to its exposure to commodity prices, Enterprise Products Partners has significant exposure to increases in interest rates. As of March 31, 2005, Enterprise Products Partners had approximately $4.2 billion of consolidated debt, of which approximately $3.0 billion was at fixed interest rates and $1.2 billion was at variable interest rates, after giving effect to existing interest rate swap arrangements. Enterprise Products Partners may from time to time enter into additional interest rate swap arrangements, which could increase its exposure to variable interest rates. As a result, its 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 Enterprise Products Partners’ common units. Any such reduction in demand for Enterprise Products Partners’ common units resulting from other more attractive investment opportunities may cause the trading price of its common units to decline.

 

The use of derivative financial instruments could result in material financial losses by Enterprise Products Partners.

 

We believe Enterprise Products Partners historically has sought to limit a portion of the adverse effects resulting from changes in oil and natural gas commodity prices and interest rates by using financial derivative instruments and other hedging mechanisms from time to time. To the extent that Enterprise Products Partners hedges its commodity price and interest rate exposures, it will forego the benefits it would otherwise experience if commodity prices or interest rates were to change in its favor. In addition, even though monitored by Enterprise Products Partners’ management, hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is imperfect, or hedging policies and procedures are not followed.

 

Enterprise Products Partners’ pipeline integrity program may impose significant costs and liabilities on it.

 

In December 2003, the U.S. Department of Transportation issued a final rule (effective as of February 14, 2004) requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. At this time, Enterprise Products Partners 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. Enterprise Products Partners will continue its pipeline integrity programs to assess and maintain the integrity of its pipelines. The results of these tests could cause Enterprise Products Partners to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.

 

Environmental costs and liabilities and changing environmental regulation could materially affect Enterprise Products Partners’ cash flow.

 

Enterprise Products Partners’ 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. Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both. Third parties may also have the right to pursue legal actions to enforce compliance.

 

Enterprise Products Partners 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 its operations, including the handling, manufacture, use, emission or disposal of substances and wastes.

 

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Federal, state or local regulatory measures could materially adversely affect Enterprise Products Partners’ business.

 

The Federal Energy Regulatory Commission, or FERC, regulates Enterprise Products Partners’ interstate natural gas pipelines and interstate natural gas storage facilities under the Natural Gas Act, and interstate NGL and petrochemical pipelines under the Interstate Commerce Act, while state regulatory agencies regulate Enterprise Products Partners’ intrastate natural gas and NGL pipelines, intrastate storage facilities and gathering lines.

 

Under the Natural Gas Act, the FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services is comprehensive and includes the rates charged for the services, terms and conditions of service and certification and construction of new facilities. The FERC requires that Enterprise Products Partners’ services are provided on a non-discriminatory basis so that all shippers have open access to its pipelines and storage. Pursuant to the FERC’s jurisdiction over interstate gas pipeline rates, existing pipeline rates may be challenged by customer complaint or by the FERC Staff and proposed rate increases may be challenged by protest.

 

Enterprise Products Partners has interests in natural gas pipeline facilities offshore from Texas and Louisiana. These facilities are subject to regulation by the FERC and other federal agencies, including the Department of Interior, under the Outer Continental Shelf Lands Act, and by the Department of Transportation’s Office of Pipeline Safety under the Natural Gas Pipeline Safety Act.

 

Enterprise Products Partners’ intrastate NGL and natural gas pipelines are subject to regulation in many states, including Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas and its intrastate natural gas pipelines are subject to regulation by the FERC pursuant to Section 311 of the Natural Gas Policy Act. Enterprise Products Partners also has natural gas underground storage facilities in Louisiana, Mississippi and Texas. Although state regulation is typically less onerous than at the FERC, proposed and existing rates subject to state regulation and the provision of services on a non-discriminatory basis are also subject to challenge by protest and complaint, respectively.

 

For a general overview of federal, state and local regulation applicable to Enterprise Products Partners’ energy infrastructure assets, please read “Business of Enterprise Products Partners—Regulation and Environmental Matters.” This regulatory oversight can affect certain aspects of Enterprise Products Partners’ business and the market for its products and could materially adversely affect its cash flow.

 

Terrorist attacks aimed at Enterprise Products Partners’ facilities could adversely affect its business.

 

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 Enterprise Products Partners’ facilities or pipelines or those of its customers could have a material adverse effect on Enterprise Products Partners’ business. An escalation of political tensions in the Middle East and elsewhere could result in increased volatility in the world’s energy markets and result in a material adverse effect on Enterprise Products Partners’ business.

 

Tax Risks to Our Unitholders

 

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

 

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

 

The anticipated after-tax benefit of an investment in our 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

 

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Index to Financial Statements

IRS on this matter. The value of our investment in Enterprise Products Partners depends largely on Enterprise Products Partners being treated as a partnership for federal income tax purposes.

 

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. 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 our anticipated cash flow and after-tax return to you, likely causing a substantial reduction in the value of our units.

 

If Enterprise Products Partners were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deduction or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our units.

 

Current law may change, causing us or Enterprise Products Partners to be treated as a corporation for federal income tax purposes or otherwise subjecting us or Enterprise Products Partners to entity level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us or Enterprise Products Partners 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 units may be adversely impacted, and the costs of any contest will be borne by our unitholders and our general partner.

 

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 units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.

 

A successful IRS contest of the federal income tax positions taken by Enterprise Products Partners may adversely impact the market for its common units, and the costs of any contest will be borne by Enterprise Products Partners, and therefore indirectly by us and the other unitholders of Enterprise Products Partners.

 

The IRS may adopt positions that differ from the positions Enterprise Products Partners takes, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions Enterprise Products Partners takes. A court may not agree with all of the positions Enterprise Products Partners takes. Any contest with the IRS may materially and adversely impact the market for Enterprise Products Partners’ common units and the prices at which the common units trade. In addition, the costs of any contest with the IRS will be borne by Enterprise Products Partners and therefore indirectly by us, as a unitholder and as the owner of the general partner of Enterprise Products Partners, and by the other unitholders of Enterprise Products Partners.

 

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

 

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

 

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Index to Financial Statements

distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

 

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

 

If you sell your units, you will recognize gain or loss equal to the difference between the amount realized and your tax basis in those units. Prior distributions to you in excess of the total net taxable income you were allocated for a unit, which decreased your tax basis in that unit, will, in effect, become taxable income to you if the unit is sold at a price greater than your tax basis in that 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, regulated investment companies and foreign persons face unique tax issues from owning units that may result in adverse tax consequences to them.

 

Investment in units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Recent legislation treats net income derived from the ownership of certain publicly traded partnerships (including us) as qualifying income to a regulated investment company. However, this legislation is only effective for taxable years of regulated investment companies beginning after October 22, 2004. For taxable years of regulated investment companies beginning on or before October 22, 2004, very little of our income will be qualifying income to a regulated investment company. 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 income tax returns and pay tax on their share of our taxable income.

 

We will treat each purchaser of our units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.

 

Because we cannot match transferors and transferees of 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 adversely affect 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 units and could have a negative impact on the value of our 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.

 

You will likely be subject to state and local taxes and return filing requirements as a result of investing in our 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 or Enterprise Products Partners do business or own property. You will likely 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 or Enterprise Products Partners 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 units.

 

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USE OF PROCEEDS

 

We expect to receive net proceeds of approximately $305 million from the sale of the 12,000,000 units we are offering, after deducting estimated offering expenses and structuring fees payable by us of approximately $3.5 million and underwriting discounts and commissions. The underwriters will not receive any discount or commission on the 2,259,259 units to be offered to entities controlled by Dan L. Duncan or on the 185,185 units to be offered to O.S. Andras, a director of Enterprise Products GP. If the underwriters exercise their option to purchase additional units in full, we expect to receive net proceeds of approximately $343.5 million.

 

We will enter into a new $525 million credit facility concurrently with the closing of this offering. Affiliates of certain underwriters in this offering, including Citigroup and Lehman Brothers, will be lenders under our new credit facility and will be partially repaid with the net proceeds of this offering. As a result, these underwriters may be deemed to have a conflict of interest with respect to this offering because they have interests in the successful completion of this offering beyond the underwriting discount and commissions they will receive. Please read “Underwriting” for further details.

 

We will use all of the net proceeds from this offering to repay approximately $305 million of indebtedness outstanding under our new credit facility. Net proceeds from any exercise of the underwriters’ option to purchase additional units will also be used to repay indebtedness under our new credit facility We expect to incur approximately $525.0 million of indebtedness under this new facility, which will be used to repay (i) $365.4 million of indebtedness owed by Enterprise Products GP to Dan Duncan LLC that was originally incurred to finance Enterprise Products GP’s purchase of a 50% interest in GulfTerra’s general partner and (ii) $159.6 million of indebtedness owed to EPCO that was assumed by us from an affiliate of EPCO as part of the contribution to us by that affiliate of 13,454,498 Enterprise Products Partners common units and a 9.9% member interest in Enterprise Products GP.

 

Immediately after the closing of this offering, we expect to have borrowings of approximately $220 million outstanding under our new credit facility bearing interest at approximately 6.0% per annum. This facility will have a maturity date in February 2006; however, we intend to refinance this indebtedness with a multi-year credit facility prior to this maturity date. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Debt Obligations—Enterprise GP Holdings.”

 

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Index to Financial Statements

CAPITALIZATION

 

The following table sets forth our cash and cash equivalents and our capitalization as of March 31, 2005:

 

    on a consolidated historical basis of Enterprise Products GP;

 

    on a pro forma basis giving effect to the following adjustments:

 

    the use of proceeds from Enterprise Products Partners’ sale of 410,249 common units in connection with its DRIP and related programs in May 2005;

 

    the issuance by Enterprise Products Partners’ operating partnership of an aggregate $500 million of senior unsecured notes in June 2005 (Senior Notes K) and the related use of proceeds;

 

    the assumption by us of $159.6 million of debt from an affiliate of EPCO in connection with the contribution to us by that affiliate of 13,454,498 Enterprise Products Partners’ common units and a 9.9% member interest in Enterprise Products GP; and

 

    the borrowing of $525.0 million by us under our new credit facility and the subsequent repayment by us of (i) $159.6 million to EPCO and (ii) $365.4 million owed by Enterprise Products GP to Dan Duncan LLC; and

 

    on a pro forma as adjusted basis to reflect the sale of 12,000,000 units in this offering and the application of the net proceeds to repay a portion of the indebtedness outstanding under our new credit facility as described under “Use of Proceeds.”

 

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The historical financial data of Enterprise Products GP presented in the table below is derived from and should be read in conjunction with Enterprise Products GP’s historical financial statements, including the accompanying notes, included elsewhere in this document (dollars in thousands). Please read our unaudited pro forma condensed consolidated financial statements included elsewhere in this prospectus for a complete description of the adjustments we have made to arrive at our pro forma and pro forma as adjusted capitalization data.

 

     As of March 31, 2005

 
     Enterprise
Products GP
Historical


    Enterprise GP
Holdings Pro
Forma


    Enterprise GP
Holdings Pro
Forma As
Adjusted


 

Cash and cash equivalents

   $ 68,132     $ 274,202     $ 274,202  
    


 


 


Long-term borrowings, including current portion:

                        

Enterprise GP Holdings amounts:

                        

$525 million credit facility

             525,000       219,980  

Enterprise Products GP amounts:

                        

$370 million note to Dan Duncan, LLC

     365,409                  

Operating Partnership amounts:

                        

Multi-Year revolving credit facility, variable rate, due September 2009

     300,000                  

Seminole Notes, 6.67% fixed-rate, $15 million due in December 2005

     15,000       15,000       15,000  

Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010

     54,000       54,000       54,000  

Senior Notes B, 7.50% fixed-rate, due February 2011

     450,000       450,000       450,000  

Senior Notes C, 6.375% fixed-rate, due February 2013

     350,000       350,000       350,000  

Senior Notes D, 6.875% fixed-rate, due March 2033

     500,000       500,000       500,000  

Senior Notes E, 4.00% fixed-rate, due October 2007

     500,000       500,000       500,000  

Senior Notes F, 4.625% fixed-rate, due October 2009

     500,000       500,000       500,000  

Senior Notes G, 5.60% fixed-rate, due October 2014

     650,000       650,000       650,000  

Senior Notes H, 6.65% fixed-rate, due October 2034

     350,000       350,000       350,000  

Senior Notes I, 5.00% fixed-rate, due March 2015

     250,000       250,000       250,000  

Senior Notes J, 5.75% fixed-rate, due March 2035

     250,000       250,000       250,000  

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

             500,000       500,000  

Dixie short-term commercial paper debt obligations

     14,000       14,000       14,000  

GulfTerra amounts:

                        

Senior Subordinated Notes, 8.50% fixed-rate, due June 2010

     3,858       3,858       3,858  

Senior Subordinated Notes, 8.50% fixed-rate, due June 2011

     1,777       1,777       1,777  

Senior Subordinated Notes, 10.625% fixed-rate, due December 2012

     84       84       84  
    


 


 


Total principal amount of debt obligations

     4,554,128       4,913,719       4,608,699  

Other, including discounts and premiums on senior notes

     (31,416 )     (32,246 )     (32,246 )
    


 


 


Total debt obligations

     4,522,712       4,881,473       4,576,453  

Minority interest

     5,315,188       5,014,221       5,014,221  

Equity

                        

Members’ equity of Enterprise Products GP

     171,908                  

Partners’ equity of GP Holdings

                        

Limited Partners

             323,675       628,695  

General Partner

             9       9  
    


 


 


Total equity

     171,908       323,684       628,704  
    


 


 


Total capitalization

   $ 10,009,808     $ 10,219,378     $ 10,219,378  
    


 


 


 

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DILUTION

 

Dilution is the amount by which the offering price paid by purchasers of units sold in this offering will exceed the net tangible book value per unit after the offering. Based on the assumed initial public offering price of $27.00 per unit, on a pro forma as adjusted basis as of March 31, 2005, after giving effect to the offering of 12,000,000 units, our net tangible book value was $600.4 million, or $6.93 per unit. Purchasers of units in this offering will experience substantial and immediate dilution in net tangible book value per unit for financial accounting purposes, as illustrated in the following table.

 

Assumed initial public offering price per unit

          $ 27.00

Pro forma net tangible book value per unit before the offering (1)

   $ 3.96       

Increase in net tangible book value per unit attributable to purchasers in the offering

     2.97       
    

      

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

            6.93
           

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

          $ 20.07
           


(1) Determined by dividing the total number of units (74,667,332 units and the 0.01% general partner interest, which has a dilutive effect equivalent to 7,467 units) to be issued to our general partner and its affiliates for their contribution of assets and liabilities to us into the net tangible book value of the assets and liabilities contributed to us by affiliates of EPCO of $295.3 million. Our general partner’s dilutive effect equivalent was determined by multiplying the total number of units deemed to be outstanding (i.e., the total number of units outstanding divided by 99.99%) by our general partner’s 0.01% general partner interest.
(2) Determined by dividing the total number of units (86,667,332 units and the 0.01% general partner interest, which has a dilutive effect equivalent to 7,467 units) to be outstanding after the offering into our pro forma net tangible book value of $600.4 million, after giving effect to the application of the net proceeds of the offering.

 

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of units in this offering (dollars in millions), including the dilutive effect of equivalent units for the general partner interest.

 

     Units Acquired

    Total Consideration

 
     Number

   Percent

    Amount

   Percent

 

General partner and its affiliates (1)(2)

   74,674,799    86.1 %   $ 323.7    51.5 %

New investors (3)

   12,000,000    13.9       305.0    48.5  
    
  

 

  

Total

   86,674,799    100.0 %   $ 628.7    100.0 %
    
  

 

  


(1) Upon the consummation of this offering, our general partner and its affiliates, excluding the employee partnership and other entities controlled by Dan L. Duncan that will be offered units in this offering, will own an aggregate of 74,667,332 units and the 0.01% general partner interest having a dilutive effect equivalent to 7,467 units.
(2) The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with generally accepted accounting principles. Book value of the consideration provided by our general partner and its affiliates, as of March 31, 2005, was $483.3 million.
(3) Includes an estimated 2,259,259 units to be offered to the employee partnership and other entities controlled by Dan L. Duncan.

 

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

 

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more 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 and Enterprise Products Partners’ business. Unless otherwise stated, the information presented in this section assumes that the underwriters will exercise their option to purchase additional units in full.

 

For additional information regarding our historical and pro forma operating results, you should refer to the historical financial statements of Enterprise Products GP for the years ended December 31, 2004, 2003 and 2002, the historical financial statements of Enterprise Products GP for the three months ended March 31, 2005 and 2004, and the unaudited pro forma condensed consolidated financial statements of Enterprise GP Holdings for the year ended December 31, 2004 and three months ended March 31, 2005, included elsewhere in this prospectus.

 

General

 

Rationale for Our Cash Distribution Policy. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our available cash rather than our retaining it. It is important for you to understand that our cash-generating assets currently consist only of our partnership interests in Enterprise Products Partners from which we receive quarterly distributions. We currently have no independent operations separate from those of Enterprise Products Partners. Because we believe our primary acquisition focus will involve the acquisition of cash-generating interests similar to our partnership interests in Enterprise Products Partners, and since such interests are characterized by relatively low cash requirements for general and administrative expenses and borrowing-related costs, we believe that our investors are best served by our distribution of all of our available cash as described below. 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 tax. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.

 

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

 

    Our distributions will be subject to certain financial condition covenants under our new credit facility, which will require us to maintain a consolidated debt to EBITDA ratio of 4.00 to 1.00 at the end of each fiscal quarter. If we are unable to satisfy this restriction under our new credit facility, we would be prohibited from making a distribution to you notwithstanding our stated distribution policy.

 

    As described below, our board of directors may establish cash reserves for the prudent conduct of our business, and the establishment of those reserves could result in a reduction of our stated distribution level.

 

    While our partnership agreement requires us to distribute our available cash, our partnership agreement, including our cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our units. Following completion of this offering and assuming the full exercise of the underwriters’ option to purchase additional units, affiliates of our general partner, including the employee partnership, will own approximately 87.2% of our outstanding units and will have the ability to amend our partnership agreement. All of these affiliates are controlled by Dan L. Duncan.

 

    Even if our cash distribution policy is not modified or revoked, the amount of distributions paid and the decision to make any distribution is at the discretion and subject to the approval of the board of directors of our general partner, taking into consideration the terms of our partnership agreement.

 

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

 

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    We may lack sufficient cash to pay distributions to our unitholders due to increases in general and administrative expenses, principal and interest payments required under our new credit facility or other debt we may incur in the future, working capital requirements and other cash needs.

 

Our Cash Distribution Policy Limits Our Ability to Grow. Because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. Initially and until such time as we expand our business through acquisitions, our growth will be dependent upon Enterprise Products Partners’ ability to increase its aggregate cash distributions to its partners since our cash-generating assets currently consist only of our partnership interests in Enterprise Products Partners.

 

Enterprise Products Partners’ Ability to Grow is Primarily Dependent on its Ability to Access External Growth Capital . Consistent with the terms of its partnership agreement, Enterprise Products Partners has distributed most of the cash generated by its operations. As a result, it has relied on external financing sources, including commercial borrowing and other debt and common unit issuances, to fund its acquisition and growth capital expenditures. However, to the extent Enterprise Products Partners is unable to finance growth externally, its cash distribution policy will significantly impair its ability to grow. In addition, to the extent Enterprise Products Partners issues additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that Enterprise Products Partners will be unable to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders. The incurrence of additional commercial or other debt to finance its growth strategy would result in increased interest expense to Enterprise Products Partners, which in turn may impact the available cash that we have to distribute to our unitholders.

 

Our Initial Distribution Rate

 

Our Cash Distribution Policy. Upon the closing of this offering, the board of directors of our general partner will adopt a cash distribution policy for our units pursuant to which we will declare an initial quarterly distribution of $0.25 per unit, or $1.00 per unit on an annualized basis, to be paid no later than 50 days after the end of each fiscal quarter. This equates to an aggregate cash distribution of $22.1 million per complete quarter or $88.2 million per year based on the number of units to be outstanding immediately after completion of this offering, assuming the underwriters exercise their option to purchase additional units in full. On or about November 18, 2005, we will pay a prorated quarterly distribution (based on our initial quarterly distribution of $0.25 per unit) for the period between the consummation of our initial public offering and September 30, 2005.

 

The following table sets forth the assumed number of our units outstanding upon the closing of this offering, assuming the underwriters exercise their option to purchase additional units in full, and the estimated aggregate distribution amounts to be paid on such units during the year following the closing of this offering at our initial annual distribution of $1.00 per unit.

 

Distributions to our public unitholders (11,257,408 units)

   $ 11,257,408

Distributions to employee partnership (1,888,889 units)

     1,888,889

Distributions to Dan L. Duncan, EPCO, Dan Duncan LLC and their other controlled affiliates (75,037,702 units)

     75,037,702
    

Total distributions we expect to pay to our unitholders

   $ 88,183,999
    

 

These distributions will not be cumulative. Consequently, if distributions on our units are not paid at the targeted levels, our unitholders will not be entitled to receive such payments in the future. We will pay our distributions on or about the 20th day of each of February, May, August and November to holders of record on or about the 13th day 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.

 

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

 

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generally mean, for each fiscal quarter, the amount of cash generated from our business in excess of the amount of cash reserves established by our general partner to, among other things:

 

    comply with applicable law or any debt instrument or other agreement applicable to us;

 

    provide funds for distributions to partners in respect of any one or more of the next four quarters;

 

    permit Enterprise Products GP to make capital contributions to Enterprise Products Partners to maintain its 2% general partner interest upon the issuance of partnership securities by Enterprise Products Partners; or

 

    otherwise provide for the proper conduct of our business.

 

Cash Distribution Policy of Enterprise Products Partners. Like us, Enterprise Products Partners has adopted a cash distribution policy that requires it to distribute its available cash to unitholders on a quarterly basis. Enterprise Products Partners’ determination of available cash takes into account the types of reserves similar to those described above. Enterprise Products Partners makes its quarterly distributions from cash generated from its operations and those distributions have grown over time as Enterprise Products Partners’ midstream energy business has grown, primarily as a result of acquisitions and internal growth projects. For additional information, please read “Enterprise Products Partners’ Cash Distribution Policy.”

 

The following table sets forth, for the periods indicated, the amount, record date and payment date of the quarterly cash distributions Enterprise Products Partners paid per common unit with respect to the quarter indicated. The actual cash distributions (i.e., payments to Enterprise Products Partners’ partners) occur within 45 days after the end of such quarter. Since its initial public offering in July 1998, Enterprise Products Partners has had an established historical record of paying quarterly cash distributions to its partners.

 

     Cash Distribution History

     Per Unit

  

Record Date


  

Payment Date


2003

                

1st Quarter

   $ 0.3625    Apr. 30, 2003    May 12, 2003

2nd Quarter

   $ 0.3625    Jul. 31, 2003    Aug. 11, 2003

3rd Quarter

   $ 0.3725    Oct. 31, 2003    Nov. 12, 2003

4th Quarter

   $ 0.3725    Jan. 30, 2004    Feb. 11, 2004

2004

                

1st Quarter

   $ 0.3725    Apr. 30, 2004    May 12, 2004

2nd Quarter

   $ 0.3725    Jul. 30, 2004    Aug. 11, 2004

3rd Quarter

   $ 0.3950    Oct. 29, 2004    Nov. 5, 2004

4th Quarter

   $ 0.4000    Jan. 31, 2005    Feb. 14, 2005

2005

                

1st Quarter

   $ 0.4100    Apr. 29, 2005    May 10, 2005

2nd Quarter (declared on July 20, 2005)

   $ 0.4200    Jul. 29, 2005    Aug. 10, 2005

 

In the sections that follow, we present the basis for our belief that we will be able to pay our initial annual distribution of $1.00 per unit. In those sections, we present two tables, including:

 

    Our “Estimated Available Cash to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA” in which we present an estimate of available cash to pay distributions to unitholders for the four quarters ending June 30, 2006, which supports our belief that we will be able to fully fund our initial annual distribution of $1.00 per unit during such period; and

 

    Our “Unaudited Pro Forma Consolidated Available Cash” in which we present our measure of pro forma consolidated available cash that would have been available for distributions to our unitholders with respect to the year ended December 31, 2004 and the twelve months ended March 31, 2005 assuming that the GulfTerra merger and other pro forma transactions described under “Enterprise GP Holdings L.P. Unaudited Pro Forma Condensed Consolidated Financial Statements” beginning on page F-3 had taken place on January 1, 2004.

 

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Estimated Consolidated Adjusted EBITDA

 

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

 

In order to fund distributions to our unitholders at our initial rate of $0.25 per unit per complete quarter, our Estimated Consolidated Adjusted EBITDA for the twelve months ending June 30, 2006 must be at least $1.1 billion. This amount represents the minimum amount of Consolidated Adjusted EBITDA necessary to permit us to distribute $0.25 per unit to our unitholders in each quarter in the four quarters ending June 30, 2006. The following presentation is intended to demonstrate a minimum base level of earnings performance of Enterprise Products Partners to allow for distributions to us and others, and for us to meet our initial cash distribution rate of $0.25 for the the four quarters ending June 30, 2006. Our management believes the actual financial performance results of Enterprise Products Partners during this period of time will exceed this minimum base level. The information listed under “—Assumptions and Considerations” below reflects various operating, financial and other assumptions of our management, and the basis for our belief that we will also generate a minimum base level Consolidated Adjusted EBITDA of approximately $1.1 billion for the twelve months ending June 30, 2006.

 

Our definition of EBITDA included under “Summary—Non-GAAP Financial Measures” differs from “Estimated Consolidated Adjusted EBITDA,” used for the purpose of demonstrating a minimum level of earnings performance related to our ability to make cash distributions. We define Consolidated Adjusted EBITDA as net income or loss plus interest expense, income taxes, depreciation and amortization expense, and minority interest owned by third parties and related parties other than us. Amounts such as gains on the sale of assets and provisions for impairment losses are non-cash items within Cash Provided by Operating Activities in our statements of consolidated cash flows but are included as components of Estimated Consolidated Adjusted EBITDA, and thus are reconciling items in arriving at Estimated Consolidated Adjusted EBITDA. Similarly, the net effect of changes in operating accounts are not included in our Estimated Consolidated Adjusted EBITDA, and thus are reconciling items in the reconciliation of Cash Provided by Operating Activities and Estimated Consolidated Adjusted EBITDA. Our measure of Estimated Consolidated Adjusted EBITDA should not be considered an alternative 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.

 

In the following table entitled “Estimated Cash Available to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA,” we estimate that our Estimated Consolidated Adjusted EBITDA will be approximately $1.1 billion for the twelve months ending June 30, 2006. We refer to this amount as our “Estimated Consolidated Adjusted EBITDA.” We have also determined that if our Estimated Consolidated Adjusted EBITDA for such period is at or above our estimate, we would be permitted to make our distributions under the restricted payments covenants in our credit agreement, and Enterprise Products Partners would also be able to make its distributions under its credit agreements.

 

You should read “—Assumptions and Considerations” for a discussion of the material assumptions underlying our belief that we will be able to generate our Estimated Consolidated Adjusted EBITDA. Our belief

 

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is based on certain assumptions made by management and reflects management’s current judgment of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2006. The assumptions disclosed herein are those we believe are significant to our ability to generate the Estimated Consolidated Adjusted EBITDA. If our estimate is not achieved, we may not be able to pay the initial distribution or any amount on our units.

 

In developing our Estimated Consolidated Adjusted EBITDA, we have included sustaining and growth capital expenditure estimates for the twelve months ending June 30, 2006. Sustaining capital expenditures are capital expenditures made on an ongoing basis to maintain current operations, which do not increase operating capacity or revenues from existing levels. Growth capital expenditures consist of capital expenditures we expect Enterprise Products Partners to make to expand the operating capacity of its current operations and those it makes in connection with its business acquisitions.

 

When considering our Estimated Consolidated Adjusted EBITDA, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” and 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 following table, “Estimated Cash Available to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA.”

 

Enterprise GP Holdings

Estimated Cash Available to Pay Distributions

Based Upon Estimated Consolidated Adjusted EBITDA

 

          Twelve Months
Ending
June 30, 2006


 

Estimated Consolidated Adjusted EBITDA (a)

   $ 1,079.0  

Add:

   Borrowings for growth capital expenditures by Enterprise Products Partners (b)      570.0  
     Refinancing of Enterprise GP Holdings credit facility (c)      181.4  
     Proceeds from equity issuances of Enterprise Products Partners (d)      390.9  
     Transition support payments (e)      15.8  
    

Use of cash reserve by subsidiary of Enterprise Products Partners for scheduled repayment of debt principal in December 2005 (f)

     15.0  

Subtract:

   Cash interest expense (g)      (284.1 )
     Cash payments for income taxes (h)      (3.8 )
     Sustaining capital expenditures (i)      (81.0 )
     Growth capital expenditures (j)      (755.0 )
    

Distributions paid by Enterprise Products Partners on its common units owned by third-parties and related parties other than us (k)

     (635.5 )
     Repayments of debt principal (l)      (404.5 )
         


Estimated Cash Available at Enterprise GP Holdings to Pay Distributions

   $ 88.2  
         


Expected Cash Distributions by Enterprise GP Holdings:

        
    

Expected distribution per unit

   $ 1.00  
         


    

Distributions paid to public unitholders (based on 11,257,408 units)

   $ 11.3  
    

Distributions paid to employee partnership

     1.9  
    

Distributions paid to affiliates of EPCO (excluding employee partnership)

     75.0  
         


    

Total distributions paid to our unitholders (m)

   $ 88.2  
         


Debt Covenant Ratios

        
    

Enterprise Products Partners

        
    

Consolidated Indebtedness/Consolidated EBITDA (n)

     4.65x  
    

Enterprise GP Holdings

        
    

Consolidated Indebtedness/Consolidated EBITDA (o)

     1.85x  

 

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Notes to “Estimated Cash Available to Pay Distributions Based Upon Estimated Consolidated Adjusted EBITDA” table:

 

a) We believe that our Estimated Consolidated Adjusted EBITDA for the twelve months ending June 30, 2006 will be approximately $1.1 billion, net of our estimated operating and administrative expenses. Our Estimated Consolidated Adjusted EBITDA is approximately $141.2 million more than the pro forma Consolidated Adjusted EBITDA we would have generated for the year ending December 31, 2004 and $105.6 million more than the pro forma Consolidated Adjusted EBITDA we would have generated for the twelve months ending March 31, 2005. Our ability to generate the additional Consolidated Adjusted EBITDA necessary to achieve our minimum Estimated Consolidated Adjusted EBITDA is based on our current expectation that Enterprise Products Partners will benefit from various new capital asset projects and continued improvement in operating performance relative to historical periods. Please read “—Assumptions and Considerations” for detailed information regarding these expectations. Estimated Consolidated Adjusted EBITDA reflects the incremental general and administrative expenses of $3 million that we expect to incur as a result of our becoming a public company.

 

b) Reflects $570 million in gross borrowings under Enterprise Products Partners multi-year revolving credit facility to fund projected growth capital spending. After the application of proceeds from equity issuances (see Note (d)), we anticipate the debt principal outstanding under Enterprise Products Partners’ multi-year revolving credit facility to approximate $540 million at June 30, 2006.

 

c) Our initial $525 million credit facility matures in February 2006. It is our intention to refinance the $181.4 million balance outstanding under this facility (after the application of proceeds from this offering assuming the full exercise of the underwriters’ option to purchase additional units) with a multi-year revolving credit facility. For purposes of determining Estimated Consolidated Adjusted EBITDA, we have assumed that this second credit facility has terms identical to the first credit facility.

 

d) Reflects net cash proceeds received by Enterprise Products Partners in connection with sales of its common units through its quarterly distribution reinvestment program and an underwritten equity offering during the period. Our estimate of net proceeds from such offerings primarily consists of (i) $34.3 million from the sale of 325,000 common units each quarter in connection with Enterprise Products Partners distribution reinvestment plan and (ii) $348.8 million from the sale of 13,850,000 common units in connection with an underwritten equity offering.

 

e) Reflects cash received by Enterprise Products Partners from El Paso in connection with a contract-based receivable from El Paso recorded in connection with the GulfTerra merger. The agreements between Enterprise Products Partners and El Paso provide that for a period of three years following the closing of the GulfTerra merger, El Paso will make transition support payments to Enterprise Products Partners in annual amounts of $18 million, $15 million and $12 million for the first, second and third years of such period, respectively, payable in twelve equal monthly installments for each such year. The $15.8 million shown in the table represents the amount to be received under this agreement for the twelve months ending June 30, 2006.

 

f) Reflects the use of cash by our Seminole Pipeline Company subsidiary to make its final scheduled principal payment in December 2005. Seminole Pipeline Company voluntarily retains sufficient cash each year to meet this $15 million annual principal payment. This debt will be repaid in December 2005.

 

g) Our pro forma consolidated cash interest expense assumes interest expense for the twelve months ending June 30, 2006 to be approximately $284.1 million. Our cash interest is primarily comprised of the following:

 

  (i) Approximately $245 million associated with the current $4.3 billion in outstanding senior notes of Enterprise Products Partners. For a listing of these senior note obligations including the related fixed interest rates, please read “Capitalization.”

 

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  (ii) Approximately $22.2 million associated with $540 million in net borrowings under Enterprise Products Partners’ multi-year revolving credit facility. Our estimate of cash interest expense related to the multi-year revolving credit facility is based on the Eurodollar-based borrowing rate under this facility, which was 4.1% as of July 15, 2005. During the first six months of 2005, the range of interest rates Enterprise Products Partners paid under its multi-year revolving credit facility was between 1.67% and 4.75%.

 

  (iii) Approximately $10.9 million associated with the outstanding borrowings under Enterprise GP Holdings’ new credit facility, which is expected to have approximately $181.4 million outstanding after adjusting for this offering, assuming the full exercise of the underwriters’ option to purchase additional units. This facility is expected to bear interest at a Eurodollar-based floating rate currently assumed to be approximately 6% on average through June 30, 2006.

 

h) Reflects our estimated cash income taxes, which is primarily applicable to certain federal and/or state tax obligations of our Seminole and Dixie pipelines. Our limited partnership structure is not subject to federal income taxes. As a result, our earnings or losses for federal income tax purposes are included in the tax returns of the individual partners.

 

i) We currently estimate that our consolidated sustaining capital expenditures will be approximately $81 million for the twelve months ending June 30, 2006 in comparison to pro forma amounts of approximately $69 million and $72 million in the twelve months ended December 31, 2004 and March 31, 2005, respectively. The increased estimate sustaining capital expenditures for the twelve month period ending June 30, 2006 primarily reflects higher spending on pipeline integrity projects.

 

j) Reflects our estimate of Enterprise Products Partners’ growth capital expenditures (which includes both construction-related and acquisition-related spending) for the twelve month period ending June 30, 2006. Of the $755 million in projected spending, approximately $566 million is related to announced construction growth projects such as our Independence Hub platform and related Independence Trail pipeline and $189 million is attributable to announced acquisitions such as our planned acquisition of terminal assets from an affiliate of Ferrellgas. By comparison, our pro forma spending on growth capital projects was $1.4 billion and $1.8 billion for the twelve month periods ending December 31, 2004 and March 31, 2005, respectively. Our pro forma growth capital spending amounts included approximately $1 billion associated with the acquisition of ownership interests and assets in connection with Enterprise Products Partners’ merger with GulfTerra in September 2004.

 

k) Reflects estimated cash distributions from Enterprise Products Partners to its unitholders other than us based upon its most recent declared quarterly distribution of $0.42 per unit or $1.68 on an annualized basis. Our estimate of Enterprise Products Partners’ cash distributions is based on approximately 399 million distribution-bearing units outstanding. This amount reflects Enterprise Products Partners current outstanding common units of 384.7 million, and as described in Note (d), the issuance of 13.9 million common units in an underwritten equity offering and 1.3 million common units issued in connection with its distribution reinvestment plan.

 

l) Represents estimated principal repayments made by Enterprise Products Partners during the twelve months ending June 30, 2006. The $404.5 million in estimated principal repayments consists of (i) a $181.4 million repayment made in connection with our refinancing of our debt (see Note (c)), (ii) Seminole Pipeline Company’s final scheduled principal payment of $15 million and (iii) the application of approximately $210 million of net proceeds from equity issuances (see Note (d)) to reduce amounts outstanding under Enterprise Products Partners multi-year credit facility.

 

After giving effect to (i) this offering (assuming the full exercise of the underwriters’ option to purchase additional units) and our anticipated February 2006 refinancing of amounts estimated to be outstanding under our initial $525 million credit facility, (ii) estimated borrowings under Enterprise Products Partners multi-year revolving credit facility to fund growth capital spending and working capital requirements, (iii) estimated repayments of Enterprise Products Partners debt using net proceeds from equity issuances, and (iv) the final principal payment by Seminole Pipeline Company in December 2005, our consolidated

 

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maturities of debt for each of the twelve month periods ended June 30 would be as follows (in millions of dollars):

 

2006

        $ —  

2007

          —  

2008

          500.0

2009

          189.2

2010

          1,599.9

Thereafter

     2,801.9

 

m) Represents the amount required to fund distributions to our unitholders based upon our annualized distribution of $1.00 per unit and assuming the underwriters’ option to purchase additional units has been exercised in full.

 

n) Enterprise Products Partners current credit agreement requires that the ratio of Enterprise Products Partners’ Consolidated Indebtedness (as defined in the credit agreement) to Consolidated EBITDA (as defined in the credit agreement) for the four fiscal quarters most recently ended must be no greater than 4.75 to 1.00. You should note that Enterprise Products Partners’ Consolidated Indebtedness to Consolidated EBITDA excludes our operations and our subsidiaries’ operations that are not consolidated with Enterprise Products Partners. As indicated by the table, our Estimated Consolidated Adjusted EBITDA would have been sufficient to satisfy the ratios required by Enterprise Products Partners’ credit agreements and permit the payment of our expected distribution.

 

o) In connection with this offering, we will enter into a new $525 million credit facility. This facility is exclusively for our use and may not be drawn by Enterprise Products Partners. For additional information regarding this new credit facility, please read “Management’s Discussion and Analysis and Results of Operations—Debt Obligations—Enterprise GP Holdings.” This facility contains a financial covenant whereby Enterprise GP Holdings’ Consolidated Indebtedness (as defined in the credit agreement) to Consolidated EBITDA (as defined in the credit agreement) for the four fiscal quarters most recently ended must be no greater than 4.00 to 1.00. As indicated in the table, our ratio of Consolidated Indebtedness to Consolidated EBITDA would be 1.85x, permitting the payment of our expected distribution.

 

The following table “Unaudited Pro Forma Consolidated Available Cash” illustrates, on a pro forma basis, for our fiscal year ended December 31, 2004 and for the twelve months ended March 31, 2005, the amount of available cash that would have been available for distributions to our unitholders, assuming, in each case that the offering had been consummated at the beginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

 

As reflected in Note (m) under the following table you should be aware that “Pro forma acquisition adjustment to Consolidated Adjusted EBITDA” includes adjustments for Enterprise Products Partners’ merger with GulfTerra. The financial information for GulfTerra included herein were derived from the historical consolidated financial statements and related notes of GulfTerra for the three and nine months ended September 30, 2004 included within this prospectus. The financial information for the South Texas midstream assets for the eight months ended August 31, 2004 included herein were derived from its historical accounts and records.

 

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Enterprise GP Holdings

Unaudited Pro Forma Consolidated Available Cash

 

         Year Ended
December 31,
2004


    Twelve Months
Ended
March 31,
2005


 

Cash Provided by Operating Activities (a)

   $ 376.1     $ 520.7  

Adjustments to derive Consolidated Adjusted EBITDA:

                

Add:

  Cash payments for interest (b)      141.6       171.6  
    Cash payments for taxes (j)      0.2       0.2  
    Non-cash gains on sales of assets (c)      15.9       21.4  
    Equity earnings from unconsolidated affiliates (d)      52.8       46.2  
    Increase in restricted cash balances (e)      12.3       2.3  
    Net effect of changes in operating accounts (f)      90.5       80.6  

Subtract:

  Distributions received from unconsolidated affiliates (g)      (68.0 )     (72.9 )
    Non-cash provision for impairment losses (h)      (4.1 )     (4.1 )
    Operating lease expense paid by EPCO (i)      (7.7 )     (6.0 )
        


 


Consolidated Adjusted EBITDA (before minority interests owned by third parties and related parties other than us) (k)

   $ 609.6     $ 760.0  

Subtract:

  Additional expenses of being a public company (l)      (3.0 )     (3.0 )

Add:

 

Pro forma acquisition adjustment to Consolidated Adjusted EBITDA (m)

     331.2       216.4  
        


 


Pro Forma Consolidated Adjusted EBITDA (n)

   $ 937.8     $ 973.4  

Subtract:

  Payments for interest (o)      (248.5 )     (239.2 )
    Payments for income taxes (p)      (3.8 )     (3.9 )
    Equity earnings from unconsolidated affiliates (q)      (24.3 )     (27.3 )
    Sustaining capital expenditures (r)      (68.8 )     (71.8 )
    Growth capital expenditures (s)      (1,384.0 )     (1,779.5 )
   

Distributions by Enterprise Products Partners to its owners including related parties other than us (t)

     (586.9 )     (592.5 )

Add:

  Net borrowings under loan agreements (u)      60.6       324.2  
    Proceeds from equity offerings of Enterprise Products Partners (v)      1,695.9       1,677.9  
    Distributions received from unconsolidated affiliates (w)      37.9       52.7  
    Additional transition support payments (x)      13.5       9.0  
        


 


Pro Forma Consolidated Available Cash at Enterprise GP Holdings

   $ 429.4     $ 323.0  
        


 


    Expected cash distribution per unit    $ 1.00     $ 1.00  
        


 


    Distributions paid to public unitholders, 11,257,408 units outstanding    $ 11.3     $ 11.3  
    Distributions paid to Employee Partnership, 1,888,889 units outstanding      1.9       1.9  
   

Distributions paid to affiliates of EPCO (excluding Employee Partnership), 75,037,702 units outstanding

     75.0       75.0  
        


 


    Total expected distributions to be paid to our unitholders (y)    $ 88.2     $ 88.2  
        


 


Excess Pro Forma Consolidated Available Cash over expected cash distribution

   $ 341.2     $ 234.8  
        


 


Debt Covenant Ratios

                
    Enterprise Products Partners                 
   

Consolidated Indebtedness/Consolidated EBITDA (z)

     4.28x       4.39x  
    Enterprise GP Holdings                 
   

Consolidated Indebtedness/Consolidated EBITDA (aa)

     1.78x       1.78x  

 

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

 

(a) Reflects historical consolidated cash provided by operating activities of Enterprise Products GP obtained from its annual and quarterly statements of consolidated cash flows.

 

(b) Reflects historical consolidated amounts of interest paid by Enterprise Products GP. The increase in the historical amounts is attributable to increased levels of debt since the merger with GulfTerra in September 2004.

 

(c) Reflects historical consolidated non-cash gains on the sale of assets by Enterprise Products GP. The historical amounts primarily reflect a gain on the sale of assets of approximately $15.1 million related to the satisfaction of certain requirements of a sale agreement whereby a 50% interest in Cameron Highway was sold.

 

(d) Reflects our share of the historical earnings of our equity method investees. The historical amounts we recorded for the twelve months ended December 31, 2004 and March 31, 2005 included $32 million and $21.5 million, respectively, of equity earnings from the general partner of GulfTerra, which became a wholly owned subsidiary of Enterprise Products Partners upon completion of the GulfTerra merger. We accounted for our investment in the general partner of GulfTerra using the equity method from December 2003 through September 2004.

 

(e) Reflects restricted cash balance requirements associated with amounts held by a brokerage firm as margin deposits associated with our financial instruments portfolio and for our physical purchase of natural gas made on the NYMEX exchange.

 

(f) Primarily reflects historical consolidated changes in operating accounts, which 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.

 

(g) Reflects historical distributions we received from our equity method unconsolidated affiliates. The historical amounts we recorded for the twelve months ended December 31, 2004 and March 31, 2005 included $32.3 million and $21.7 million, respectively, of distributions from the general partner of GulfTerra.

 

(h) Reflects a non-cash asset impairment charge related to the sale of our interest in a Mississippi propane storage facility in connection with gaining regulatory approval for the GulfTerra merger. As a result of our determination of this long-lived asset’s current market value, we recorded a $4 million non-cash asset impairment charge during the third quarter of 2004.

 

(i) EPCO subleases to Enterprise Products Partners certain equipment located at its Mont Belvieu facility and 100 railcars. These subleases are part of the administrative services agreement that Enterprise Products Partners executed with EPCO in connection with its formation in 1998. EPCO holds these items pursuant to operating leases for which it has retained the corresponding cash lease payment obligation. Operating costs and expenses treat the lease payments being made by EPCO as a non-cash related party operating expense.

 

(j) Our provision for cash income taxes is primarily applicable to certain federal and/or state tax obligations of our Seminole and Dixie pipelines. Our limited partnership structure is not subject to federal income taxes.

 

(k) Consolidated Adjusted EBITDA differs from our definition of EBITDA included under “Summary—Non-GAAP Financial Measures” primarily due to in the inclusion of minority interest owned by third parties and related parties other than us of $228.7 million and $280.8 million for the twelve months ended December 31, 2004 and March 31, 2005, respectively, and other minor differences between cash and accrual adjustments.

 

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(l) Reflects an adjustment for $3 million in general and administrative expenses associated with being a public entity, including director fees, professional services and charges from EPCO related to the administrative services agreement.

 

(m) Reflects pro forma adjustments to Enterprise Products GP’s historical Consolidated Adjusted EBITDA resulting from the GulfTerra merger and related transactions. On September 30, 2004, Enterprise Products Partners and GulfTerra completed the merger of GulfTerra with a wholly owned subsidiary of Enterprise Products Partners. Additionally, Enterprise Products Partners completed certain other transactions related to the merger, including the purchase of certain midstream energy assets located in South Texas from El Paso. The GulfTerra merger transactions were recorded using the purchase method of accounting. Accordingly, since the GulfTerra merger closed during the day of September 30, 2004, our historical results of operations for the year ended December 31, 2004 and twelve months ended March 31, 2005 includes three and six months of operating results from the GulfTerra assets, respectively. Additionally, the effective closing date of our purchase of the South Texas midstream assets was September 1, 2004. As a result, our historical results of operations for the year ended December 31, 2004 and twelve months ended March 31, 2005 includes four and seven months of operating results from the South Texas midstream assets, respectively. We have included the results of operations from the GulfTerra and South Texas midstream assets in our results on a pro forma basis as if the assets were acquired on January 1, 2004.

 

Our pro forma acquisition adjustment to Consolidated Adjusted EBITDA is summarized as follows (dollars in thousands):

 

     Twelve Months Ending December 31, 2004

 
     GulfTerra

    South
Texas


   Pro Forma
Adjustments


    Pro Forma
Acquisition
Adjustment
to Adjusted
EBITDA


 

Net income

   $ 155,365     $ 44,848    $ (39,439 )   $ 160,774  

Additions to net income to derive Adjusted EBITDA:

                               

Interest expense

     82,678                      82,678  

Depreciation and amortization

     81,297       8,283              89,580  

Minority interest

     (1,825 )                    (1,825 )
    


 

  


 


Pro forma acquisition adjustment to Consolidated Adjusted EBITDA

   $ 317,515     $ 53,131    $ (39,439 )   $ 331,207  
    


 

  


 


 

     Twelve Months Ended March 31, 2005

 
     GulfTerra

    South
Texas


   Pro Forma
Adjustments


    Pro Forma
Acquisition
Adjustment
to Adjusted
EBITDA


 

Net income

   $ 99,799     $ 36,239    $ (32,719 )   $ 103,319  

Additions to net income to derive Adjusted EBITDA:

                               

Interest expense

     54,647                      54,647  

Depreciation and amortization

     55,074       5,192              60,266  

Minority interest

     (1,813 )                    (1,813 )
    


 

  


 


Pro forma acquisition adjustment to Consolidated Adjusted EBITDA

   $ 207,707     $ 41,431    $ (32,719 )   $ 216,419  
    


 

  


 


 

(n) Reflects pro forma interest payments of Enterprise GP Holdings including the pro forma effects of repayments and refinancing of debt by Enterprise Products Partners and borrowings under Enterprise GP Holdings’ new credit agreements as described in Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements included elsewhere in this prospectus.

 

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(o) Reflects our pro forma cash interest payments including the pro forma effects of repayments and refinancing of debt by Enterprise Products Partners and borrowing under our new credit agreements as described in the Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements included elsewhere in this prospectus.

 

(p) Reflects pro forma cash payments for income taxes.

 

(q) Reflects pro forma earnings from our equity method unconsolidated affiliates. The primary difference between the historical and pro forma amounts for each period is the removal of equity earnings from the general partner of GulfTerra due to its consolidation with the financial results of Enterprise Products Partners upon completion of the GulfTerra merger.

 

(r) Reflects pro forma sustaining capital expenditures. These amounts were derived by summing the historical cash outlays of Enterprise Products Partners and GulfTerra for sustaining capital expenditures.

 

(s) Reflects pro forma growth capital expenditures. These amounts were derived by summing the historical cash outlays of Enterprise Products Partners and GulfTerra for capital expenditures (excluding sustaining capital expenditures), business acquisitions and other investments. The pro forma amounts include approximately $1 billion that Enterprise Products Partners paid El Paso in connection with Step Two and Step Three of the GulfTerra merger.

 

(t) Reflects pro forma cash distributions to the owners of Enterprise Products Partners other than us for the periods shown. This amount assumes that 383.8 million distribution-bearing common units of Enterprise Products Partners are outstanding and that Enterprise Products Partners quarterly distribution rate during the twelve months ended December 31, 2004 was $1.5850 per common unit on annualized basis. The pro forma distribution shown for the twelve months ended March 31, 2005 reflects a rate of $1.60 per common unit on an annualized basis. By comparison, the actual historical distribution rates for the twelve months ended December 31, 2004 and March 31, 2005 were $1.54 and $1.5775 per common unit. The increase in Enterprise Products Partners’ annual distribution rate is primarily due to improved financial results resulting from growth capital spending.

 

(u) Reflects net pro forma borrowings by Enterprise GP Holdings including the consolidated pro forma effects of borrowings, repayments and refinancings of debt by Enterprise Products Partners as described in the Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements included elsewhere in this prospectus.

 

(v) Reflects pro forma net cash proceeds from equity offerings of Enterprise Products Partners and us as described in the Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements included elsewhere in this prospectus.

 

(w) Reflects pro forma cash distributions from unconsolidated affiliates for the periods shown. The $14.8 million increase in pro forma cash distributions for the twelve months ended March 31, 2005 versus the twelve months ended December 31, 2004 is primarily due to distributions received from Deepwater Gateway, L.L.C. during the three months ended March 31, 2005. Deepwater Gateway owns the Marco Polo platform which was placed in service during the second quarter of 2004. Deepwater Gateway did not begin paying distributions to its members until the fourth quarter of 2004.

 

(x)

Reflects pro forma cash receipts by Enterprise Products Partners from El Paso in connection with a contract-based receivable from El Paso recorded in connection with the GulfTerra merger. The agreements between Enterprise Products Partners and El Paso provide that for a period of three years following the closing of the GulfTerra merger, El Paso will make transition support payments to Enterprise Products Partners in annual amounts of $18 million, $15 million and $12 million for the first, second and third years of such period, respectively, payable in twelve equal monthly installments for each such year. The pro forma amounts of $13.5 million and $9 million shown in the table represent the additional amounts that would have been received from El Paso during the twelve months ended December 31, 2004 and March 31, 2005,

 

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respectively, necessary to remit full payment under the contract assuming that the GulfTerra merger occurred at the beginning of each period. Our historical Consolidated Adjusted EBITDA already includes $4.5 million and $9 million related to this agreement for the twelve months ending December 31, 2004 and March 31, 2005, respectively.

 

(y) Reflects the amount of cash distributions that would be paid by us to our owners based on the number of units outstanding after this offering, including units issued in connection with the full exercise of the underwriters’ option to purchase additional units.

 

(z) Enterprise Products Partners’ current credit agreement requires that the ratio of Enterprise Products Partners’ Consolidated Indebtedness (as defined in the credit agreement) to Consolidated EBITDA (as defined in the credit agreement) for the four fiscal quarters most recently ended must be no greater than 4.75 to 1.00. You should note that Enterprise Products Partners’ Consolidated Indebtedness to Consolidated EBITDA excludes our operations and our subsidiaries which are not consolidated with Enterprise Products Partners. As indicated by the table, our pro forma Consolidated Adjusted EBITDA amounts would have been sufficient to satisfy the ratios required by Enterprise Products Partners’ credit agreements and permit the payment of our expected distribution.

 

(aa) In connection with this offering, we will enter into a new $525 million credit facility. This facility is exclusively for our use and may not be drawn by Enterprise Products Partners. This facility contains a financial covenant whereby our Consolidated Indebtedness (as defined in the credit agreement) to Consolidated EBITDA (as defined in the credit agreement) for the four fiscal quarters most recently ended must be no greater than 4.00 to 1.00. As indicated in the table, our ratio of Consolidated Indebtedness to Consolidated EBITDA would have permitted the payment of our expected distribution.

 

Assumptions and Considerations

 

We believe that our partnership interests in Enterprise Products Partners will generate sufficient cash flow to enable us to pay our initial quarterly distribution of $0.25 per unit on all of our units for the four quarters ending June 30, 2006. Our belief is based on a number of current assumptions that we believe to be reasonable over the next four quarters, primarily including:

 

    Enterprise Products Partners will continue to pay its recently declared quarterly distribution of $0.42 per common unit over the next four quarters and that the amount of cash distributions we receive from Enterprise Products Partners will be equal to or greater than $88.2 million;

 

    In preparing our estimate, we assumed that commodity prices for the twelve months ending June 30, 2006 will approximate $6.00 per MMBtu for natural gas, $44.00 per barrel for crude oil and weighted-average $0.74 per gallon for natural gas liquids. On a pro forma basis for the twelve months ending December 31, 2004, commodity prices averaged $6.12 per MMBtu for natural gas, $41.45 per barrel for crude oil and $0.73 per gallon for weighted-average natural gas liquids. On a pro forma basis for the twelve months ending March 31, 2005, commodity prices averaged $6.27 per MMBtu for natural gas, $45.06 per barrel for crude oil and weighted-average $0.77 per gallon for natural gas liquids;

 

   

Our most significant measures of transportation, production and processing volumes for the twelve months ending June 30, 2006 will approximate the following: (i) natural gas pipeline transportation rates of 7.9 TBtu/d; (ii) NGL pipeline transportation rates of 1.6 million barrels per day; (iii) crude oil transportation rates of 220 thousand barrels per day; (iv) butane isomerization processing volumes of 70 thousand barrels per day; and (v) NGL and propylene fractionation volumes of 420 thousand barrels per day. By comparison, Enterprise Products Partners’ significant actual transportation, production and processing volumes since the completion of the GulfTerra merger on September 30, 2004 averaged the following: (i) natural gas pipeline transportation rates of 7.5 Tbtu/d; (ii) NGL pipeline transportation rates of 1.4 million barrels per day; (iii) crude oil transportation rates of 132 thousand barrels per day; (iv) butane isomerization processing volumes of 76 thousand barrels per day; and (v) NGL and propylene fractionation volumes of 382 thousand barrels per day. Our actual transportation, production

 

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and processing volume statistics are expected to increase due to the full year operations of GulfTerra over the twelve months ending June 30, 2006 and other improved operating performance of our assets. Of the more notable increases, crude oil transportation volumes are expected to increase approximately 100 thousand barrels per day from historical levels as a result of additional volumes transported by the Cameron Highway Oil Pipeline, which received its first volumes during the first quarter of 2005;

 

    Enterprise Products Partners’ gross operating margin for the twelve months ending June 30, 2006 will be at least $1.1 billion, as compared to a pro forma $1.0 billion and $1.1 billion for the twelve months ending December 31, 2004 and March 31, 2005, respectively. The following is a reconciliation of Consolidated Adjusted EBITDA on a pro forma and estimated basis for the periods indicated (dollars in million):

 

 

     Pro Forma

   Estimated

     Twelve
Months
Ending
December 31,
2004


   Twelve
Months
Ending
March 31,
2005


   Twelve
Months
Ending
June 30,
2006


Consolidated Adjusted EBITDA

   $ 937.8    $ 973.4    $ 1,079.0

Add consolidated general and administrative costs

     96.8      88.8      65.0
    

  

  

Gross Operating Margin

   $ 1,034.6    $ 1,062.2    $ 1,144.0
    

  

  

 

For a definition of gross operating margin, please read “Summary—Non-GAAP Financial Measures.” The primary difference between gross operating margin and Consolidated Adjusted EBITDA is that general and administrative expenses are subtracted to calculate Consolidated Adjusted EBITDA. The expected increase in gross operating margin for the twelve months ending June 30, 2006 is primarily due to:

 

    On a pro forma basis for the twelve months ending December 31, 2004 and March 31, 2005, Consolidated Adjusted EBITDA was reduced by approximately $24.0 million and $28.0 million, respectively, due to the negative effects of Hurricane Ivan, a Category 4 hurricane that damaged offshore production facilities in September 2004 and reduced the volumes delivered to certain of our natural gas processing, NGL fractionation and pipeline facilities.

 

    Reduced general and administrative costs as a result of integrating the operations of Enterprise Products Partners and GulfTerra. We expect that general and administrative costs for the twelve months ending June 30, 2006 will approximate $65 million. On a pro forma basis for the twelve months ending December 31, 2004 and March 31, 2005, general and administrative costs were $96.8 million and $88.8 million, respectively. Since completion of the GulfTerra merger, Enterprise Products Partners has consolidated certain general and administrative functions to reduce overhead costs;

 

    Increased gross operating margin from NGL marketing activities due to improved inventory management practices. The second quarter of 2004 historical amounts included a loss of $13.4 million associated with the ineffectiveness of a practice that we used to manage our NGL production and inventory on a seasonal basis. We expect that gross operating margin from our NGL marketing activities will approximate $30 million for the twelve months ending June 30, 2006. On a pro forma basis, the gross operating margin related to our NGL marketing activities was $8.2 million and $15.2 million for the twelve months ended December 31, 2004 and March 31, 2005, respectively;

 

   

Increased gross operating margin from our Marco Polo offshore pipelines, which began receiving initial production in July 2004, as a result of receiving production from the third-party K-2, K-2 North and Ghengis Khan production fields in the Gulf of Mexico. The Marco Polo pipelines went into service during the second quarter of 2004 and historically transported volumes from the Marco Polo production field in the Gulf of Mexico. The K-2, K-2 North and Ghengis Khan production

 

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fields are new developments that have either started production since March 31, 2005 or are expected to begin producing activities during the twelve months ending June 30, 2006. We expect that gross operating margin from the Marco Polo pipelines to approximate $30 million for the twelve months ending June 30, 2006 compared to $3.7 million of pro forma gross operating margin we recorded during the twelve months ended December 31, 2004 and March 31, 2005.

 

    Increased gross operating margin from our octane-additive production facility as a result of completing modifications to produce isooctane during the second quarter of 2005. We expect that gross operating margin from this facility will approximate $15 million for the twelve months ending June 30, 2006. On a pro forma basis, this facility generated gross operating margin of $1.8 million during the twelve months ended December 31, 2004 and a loss of $5.4 million during the twelve months ended March 31, 2005. The facility ceased production activities from November 2004 to May 2005 to complete the modifications to the plant. Initial start-up expenses reduced Consolidated Adjusted EBITDA for the pro forma 12-month period ending March 31, 2005 by approximately $4 million. Previously, this facility produced MTBE; and

 

    Increased gross operating margin from our Norco NGL fractionation facility due to new production from offshore Gulf of Mexico developments and production that was shut-in during 2004 as a result of the effects of Hurricane Ivan. We expect that gross operating margin from this facility will approximate $45 million for the twelve months ending June 30, 2006. On a pro forma basis, this facility generated gross operating margin of $34.9 million and $33.6 million during the twelve months ended December 31, 2004 and March 31, 2005, respectively;

 

 

    Enterprise Products Partners will complete growth capital projects on time and within budget;

 

    Enterprise Products Partners will be able to access debt and equity capital markets and be able to obtain financing arrangements to support its commercial goals, including growth capital spending, on reasonable terms. In addition, we assume that we will be able to refinance our $525 million credit facility prior to its maturity date in February 2006 on reasonable terms;

 

    We and Enterprise Products Partners will remain in compliance with the restrictive financial covenants in our existing and future debt agreements such that our ability to pay distributions to our partners is not encumbered;

 

    Our annual cash payments for interest under the $525 million credit facility will not exceed $13.2 million;

 

    Our general and administrative expenses will not exceed $3 million;

 

    There will be not be any new federal, state or local regulation of the midstream energy industry, or a new interpretation of existing regulation, that will be materially adverse to our or Enterprise Products Partners’ business;

 

    There will not be any major adverse change in the midstream energy industry or in general economic conditions; and

 

    Market, regulatory, insurance and overall economic conditions will not change substantially.

 

While we believe that these assumptions are reasonable in light of our current beliefs concerning future events, the assumptions are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash that Enterprise Products Partners generates, and thus the cash we would receive from our investments in its general partner and common units, could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make our initial quarterly and annual distributions on our units, in which event the market price of our units may decline materially. Consequently, the statement that we believe that we will have sufficient available cash to pay the initial

 

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distribution on our units for each quarter through June 30, 2006 should not be regarded as a representation by us or the underwriters or any other person that we will make such a distribution. When reading this section, you should keep in mind the risk factors and other cautionary statements under the heading “Risk Factors” in this prospectus.

 

Sources of Distributable Cash and Incentive Distribution Rights

 

Our only cash-generating assets are our partnership interests in Enterprise Products Partners. Therefore, as Enterprise Products Partners makes quarterly distributions to its partners, we receive our share of such distributions based on our partnership interests in Enterprise Products Partners. Our assets consist of the following partnership interests in Enterprise Products Partners contributed to us by EPCO:

 

    a 100% ownership of Enterprise Products GP, which owns a 2% general partner interest in Enterprise Products Partners that entitles us to receive 2% of the cash distributed by Enterprise Products Partners;

 

    the incentive distribution rights associated with Enterprise Products Partners’ general partner interest, which entitle us to receive increasing percentages of the cash distributed by Enterprise Products Partners (up to a maximum of 25%) as Enterprise Products Partners’ per unit distribution increases; and

 

    13,454,498 common units of Enterprise Products Partners, representing an approximate 3.4% limited partner interest in Enterprise Products Partners.

 

Because the incentive distributions currently participate at the maximum 25% sharing level (inclusive of the 2% general partner interest) in all distributions made by Enterprise Products Partners above $0.3085 per unit, future growth in distributions we receive from Enterprise Products Partners will not result from an increase in the sharing level associated with the incentive distribution rights. Please read “Enterprise Products Partners’ Cash Distribution Policy—Incentive Distributions.”

 

Incentive Distribution Rights—Hypothetical Allocations of Distributions to Us and Enterprise Products Partners’ Other Unitholders

 

Our assets include the incentive distribution rights associated with Enterprise Products GP’s 2% general partner interest in Enterprise Products Partners. Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions after certain target distribution levels have been archived. For any quarter, Enterprise Products Partners will make distributions among its unitholders and Enterprise Products GP in the following manner:

 

    First, 98% to all of Enterprise Products Partners’ common unitholders, pro rata, and 2% to Enterprise Products GP, until the common unitholders have received a total of $0.253 per unit for that quarter in respect of each outstanding unit (the first target distribution).

 

    Second, 85% to all of Enterprise Products Partners’ common unitholders, pro rata, and 15% to Enterprise Products GP, until the common unitholders have received a total of $0.3085 per unit for that quarter in respect of each outstanding unit (the second target distribution).

 

    Thereafter, 75% to all of Enterprise Products Partners’ common unitholders, pro rata, and 25% to Enterprise Products GP.

 

The table set forth below illustrates the percentage allocations among the non-affiliated Enterprise Products Partners unitholders and us as a result of certain assumed quarterly distribution payments per unit made by Enterprise Products Partners, including the target distribution levels contained in Enterprise Products Partners’ partnership agreement. This information is based upon:

 

    Enterprise Products Partners’ 384,695,836 common units outstanding as of July 15, 2005; and

 

    our ownership of (i) a 2% general partner interest, (ii) the associated incentive distribution rights and (iii) 13,454,498 of Enterprise Products Partners’ common units.

 

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The amounts presented below are intended to be illustrative of the way in which we are entitled to an increasing share of distributions from Enterprise Products Partners as total distributions from Enterprise Products Partners increase and are not intended to represent a prediction of future performance.

 

Enterprise Products Partners’ Quarterly
Distribution Per Unit


  Total
Annual
Distributions


  Distributions to
Non-Affiliated
Enterprise
Products
Partners
Unitholders


    Distributions to Us from
Interests in Enterprise Products
Partners


 

Total
Distributions

to Us


 
    $

   % of
Total


    General
Partner
Interest


  Incentive
Distribution
Rights


  Common
Units


  $

  % of
Total


 
    (Dollars in millions)  

First Target Distribution ($0.253)

  $ 397.3   $ 375.7    94.6 %   $ 7.9   $ 0.0   $ 13.7   $ 21.6   5.4 %

Second Target Distribution ($0.3085)

    497.7     458.1    92.0 %     9.7     13.3     16.6     39.6   8.0 %

Other Hypothetical Distributions:

                                                

$0.3425

    567.5     508.6    89.6 %     10.7     29.8     18.4     58.9   10.4 %

$0.360

    603.4     534.6    88.6 %     11.3     38.1     19.4     68.8   11.4 %

$0.3775

    639.3     560.6    87.7 %     11.8     46.6     20.3     78.7   12.3 %

$0.400

    685.5     594.0    86.7 %     12.6     57.4     21.5     91.5   13.3 %

$0.420 (current)

    726.5     623.7    85.8 %     13.2     67.0     22.6     102.8   14.2 %

$0.440

    767.5     653.4    85.1 %     13.8     76.6     23.7     114.1   14.9 %

$0.4625

    813.7     686.8    84.4 %     14.5     87.5     24.9     126.9   15.6 %

$0.4875

    865.0     723.9    83.7 %     15.3     99.6     26.2     141.1   16.3 %

$0.510

    911.2     757.4    83.1 %     16.0     110.4     27.4     153.8   16.9 %

Enterprise Products Partners made incentive cash distributions to Enterprise Products GP of $32.4 million, $19.7 million and $9.8 million during the years ended December 31, 2004, 2003 and 2002, respectively.

 

 

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Index to Financial Statements

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

 

We were formed in April 2005 and therefore do not have any historical financial statements for 2004. As a result of being under common control with Enterprise Products GP, our unaudited pro forma condensed consolidated financial information reflects the unaudited pro forma condensed consolidated financial information of Enterprise Products GP. Likewise, Enterprise Products Partners’ financial information is consolidated with Enterprise Products GP due to the same common control considerations.

 

The following tables set forth, for the periods and at the dates indicated, selected historical financial and operating data for Enterprise Products GP and our selected pro forma financial data. The selected historical statement of consolidated operations data for the years ended December 31, 2004, 2003 and 2002 and consolidated balance sheet data at December 31, 2004 and 2003 should be read in conjunction with the audited financial statements of Enterprise Products GP included elsewhere in this prospectus. The selected historical statement of consolidated operations data for the three months ended March 31, 2005 and 2004 and consolidated balance sheet data at March 31, 2005 should be read in conjunction with the unaudited financial statements of Enterprise Products GP included elsewhere in this prospectus.

 

Our selected unaudited pro forma financial information gives effect to the following transactions:

 

    the completion by Enterprise Products of its merger with GulfTerra and the related transactions and financings;

 

    the use of proceeds from the sale of 17,250,000 common units by Enterprise Products Partners in each of May 2004, August 2004 and February 2005 and from the issuance of 1,926,810 common units by Enterprise Products Partners in connection with its DRIP and related programs during the first six months of 2005;

 

    the issuance by Enterprise Products Partners’ operating partnership of $500 million of senior unsecured notes in each of March 2005 and June 2005 and the related use of proceeds;

 

    the assumption by us of $159.6 million of debt from an affiliate of EPCO in connection with the contribution to us by that affiliate of 13,454,498 Enterprise Products Partners common units and a 9.9% member interest in Enterprise Products GP; and

 

    the borrowing of $525.0 million by us under our new credit facility and the subsequent repayment by us of (i) $159.6 million to EPCO and (ii) $365.4 million owed by Enterprise Products GP to Dan Duncan LLC.

 

Our pro forma as adjusted financial information gives effect to the sale of 12,000,000 units in this offering and the application of the net proceeds to repay a portion of the indebtedness outstanding under our new credit facility as described under “Use of Proceeds.”

 

The unaudited pro forma condensed statements of consolidated operations for the three months ended March 31, 2005 and for the year ended December 31, 2004 assumes the pro forma transactions occurred on January 1, 2004 (to the extent not already reflected in the historical statements of consolidated operations of each entity). The unaudited pro forma condensed consolidated balance sheet shows the financial effects of the pro forma transactions as if they had occurred on March 31, 2005 (to the extent not already recorded in the historical balance sheet data of Enterprise Products GP).

 

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The following table presents selected historical cash distribution information of Enterprise Products Partners. This table also presents the cash distributions paid in respect of the partnership interests in Enterprise Products Partners contributed to us by EPCO (in millions, except per unit amounts).

 

     For the Year Ended December 31,

     2000

   2001

   2002

   2003

   2004

Selected Cash Distribution Data:

      

Cash distribution per unit paid by Enterprise Products Partners

   $ 1.03    $ 1.16    $ 1.33    $ 1.44    $ 1.51
    

  

  

  

  

Average number of Enterprise Products Partners distribution bearing units outstanding

     134.4      138.4      153.1      198.1      259.9
    

  

  

  

  

Cash distributions paid to Enterprise Products GP by Enterprise Products Partners:

                                  

From 2% general partner interest

   $ 2.8    $ 3.3    $ 4.3    $ 6.0    $ 8.1

From associated incentive distribution rights

     0.4      3.2      9.8      19.7      32.4
    

  

  

  

  

Total distributions paid to Enterprise Products GP

     3.2      6.5      14.1      25.7      40.5

Cash distributions paid by Enterprise Products Partners on 13,454,498 of its common units

     13.8      15.6      17.9      19.4      20.3
    

  

  

  

  

Total cash distributions

   $ 17.0    $ 22.1    $ 32.0    $ 45.1    $ 60.8
    

  

  

  

  

 

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The following tables present selected historical consolidated financial and operating data of Enterprise Products GP and pro forma consolidated financial information for us for the periods indicated (dollars in thousands, except per unit amounts).

 

                                  Enterprise GP Holdings

 
    Consolidated Historical for Enterprise Products GP

   

For the Year Ended

December 31, 2004


 
    For the Year Ended December 31,

    Pro
Forma


   

Pro Forma

As Adjusted


 
    2000

    2001

    2002

    2003

    2004

     

Statement of Consolidated Operations Data: (1)

       

Revenues

  $ 3,049,020     $ 3,154,369     $ 3,584,783     $ 5,346,431     $ 8,321,202     $ 9,615,119     $ 9,615,119  

Costs and expenses:

                                                       

Operating costs and expenses

    2,801,060       2,862,582       3,382,839       5,046,777       7,904,336       8,971,209       8,971,209  

General and administrative expenses

    28,505       30,632       44,109       39,164       47,264       96,766       96,766  
   


 


 


 


 


 


 


Total costs and expenses

    2,829,565       2,893,214       3,426,948       5,085,941       7,951,600       9,067,975       9,067,975  
   


 


 


 


 


 


 


Equity in income (loss) of unconsolidated affiliates

    24,119       25,358       35,253       (13,960 )     52,787       24,830       24,830  
   


 


 


 


 


 


 


Operating income

    243,574       286,513       193,088       246,530       422,389       571,974       571,974  

Other income (expense):

                                                       

Interest expense

    (33,581 )     (52,487 )     (101,580 )     (140,806 )     (161,589 )     (266,792 )     (248,491 )

Dividend income from unconsolidated affiliates

    7,091       3,462       4,737       5,595                          

Loss due to early redemption of debt

                                            (16,285 )     (16,285 )

Other, net

    5,379       6,881       2,696       914       2,130       3,802       3,802  
   


 


 


 


 


 


 


Total

    (21,111 )     (42,144 )     (94,147 )     (134,297 )     (159,459 )     (279,275 )     (260,974 )

Income before income taxes, minority interest and changes in accounting principles

    222,463       244,369       98,941       112,233       262,930       292,699       311,000  

Provision for income taxes

                    (1,634 )     (5,293 )     (3,761 )     (3,761 )     (3,761 )
   


 


 


 


 


 


 


Income before minority interest and changes in accounting principles

    222,463       244,369       97,307       106,940       259,169       288,938       307,239  

Minority interest (2)

    (217,909 )     (236,570 )     (86,805 )     (86,783 )     (228,716 )     (272,688 )     (272,688 )
   


 


 


 


 


 


 


Income from continuing operations

    4,554       7,799       10,502       20,157       30,453     $ 16,250     $ 34,551  
                                           


 


Cumulative effect of changes in accounting principles

                                    216                  
   


 


 


 


 


               

Net income

  $ 4,554     $ 7,799     $ 10,502     $ 20,157     $ 30,669                  
   


 


 


 


 


               

Earnings per unit, basic and diluted

                                          $ 0.22     $ 0.40  
                                           


 


Consolidated Balance Sheet Data (at period end) (1):

                                                       

Total assets

  $ 1,951,250     $ 2,428,540     $ 4,235,494     $ 4,802,802     $ 11,315,901                  

Total debt (3)

    403,847       855,278       2,246,463       2,139,548       4,647,669                  

Combined equity (4)

    18,725       26,854       25,966       36,443       164,883                  

Other Financial Data (1):

                                                       

Cash flows provided by operating activities

    357,145       273,109       326,256       421,606       376,068                  

Cash flows used in investing activities

    (268,799 )     (491,213 )     (1,708,348 )     (656,976 )     (1,299,119 )                

Cash flows provided by (used in) financing activities

    (33,754 )     291,862       1,265,712       247,556       917,591                  

Distributions received from unconsolidated affiliates

    37,267       45,054       57,662       31,882       68,027                  

Equity in (income) loss from unconsolidated affiliates

    (24,119 )     (25,358 )     (35,253 )     13,960       (52,787 )                

Gross operating margin

  $ 320,615     $ 375,944     $ 332,349     $ 410,415     $ 655,191     $ 1,047,513     $ 1,047,513  

EBITDA

  $ 75,445     $ 111,402     $ 199,822     $ 282,057     $ 391,403     $ 675,422     $ 675,422  

Operating Data (1):

                                                       

Offshore Pipelines & Services, net:

                                                       

Natural gas transportation volumes (BBtus/d)

            566       500       433       2,081                  

Crude oil transportation volumes (MBbls/d)

                                    138                  

Platform gas treating (BBtus/d)

                                    306                  

Platform oil treating (MBbls/d)

                                    14                  

Onshore Natural Gas Pipelines & Services, net:

                                                       

Natural gas transportation volumes (BBtus/d)

            783       701       600       5,638                  

NGL Pipelines & Services, net:

                                                       

NGL transportation volumes (MBbls/d)

    339       420       1,306       1,275       1,411                  

NGL fractionation volumes (MBbls/d)

    213       204       235       227       307                  

Equity NGL production (MBbls/d)

    72       63       73       43       129                  

Fee-based natural gas processing volumes (MMcf/d)

                            194       1,692                  

Petrochemical Services, net:

                                                       

Butane isomerization volumes (MBbls/d)

    74       80       84       77       76                  

Propylene fractionation volumes (MBbls/d)

    33       31       55       57       56                  

Octane additive production volumes (MBbls/d)

    5       5       5       4       10                  

Petrochemical transportation volumes (MBbls/d)

    28       33       46       68       71                  

 

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    Consolidated Historical for
Enterprise Products GP


     Enterprise GP Holdings

 
    For the Three Months
Ended March 31,


     For the Three Months
Ended March 31, 2005


 
    2004

    2005

     Pro Forma

     Pro Forma
As Adjusted


 

Statement of Consolidated Operations Data: (1)

                                 

Revenues

  $ 1,704,890     $ 2,555,522      $ 2,555,522      $ 2,555,522  

Costs and expenses:

                                 

Operating costs and expenses

    1,621,508       2,383,644        2,389,202        2,389,202  

General and administrative expenses

    9,498       15,153        15,903        15,903  
   


 


  


  


Total costs and expenses

    1,631,006       2,398,797        2,405,105        2,405,105  
   


 


  


  


Equity in income of unconsolidated affiliates

    14,867       8,279        7,966        7,966  
   


 


  


  


Operating income

    88,751       165,004        158,383        158,383  

Other income (expense):

                                 

Interest expense

    (32,618 )     (59,052 )      (59,704 )      (55,191 )

Other, net

    165       924        924        924  
   


 


  


  


Total

    (32,453 )     (58,128 )      (58,780 )      (54,267 )

Income before income taxes, minority interest and changes in accounting principles

    56,298       106,876        99,603        104,116  

Provision for income taxes

    (1,625 )     (1,769 )      (1,769 )      (1,769 )
   


 


  


  


Income before minority interest and changes in accounting principles

    54,673       105,107        97,834        102,347  

Minority interest (2)

    (43,608 )     (95,664 )      (88,144 )      (88,144 )
   


 


  


  


Income from continuing operations

    11,065       9,443      $ 9,690      $ 14,203  
                    


  


Cumulative effect of changes in accounting principles

    216                            
   


 


                 

Net income

  $ 11,281     $ 9,443                    
   


 


                 

Earnings per unit, basic and diluted

                   $ 0.13      $ 0.16  
                    


  


Consolidated Balance Sheet Data (at period end) (1):

                                 

Total assets

          $ 11,527,765      $ 11,737,335      $ 11,737,335  

Total debt (3)

            4,522,712        4,881,473        4,576,453  

Combined equity (4)

            171,908        323,684        628,704  

Other Financial Data (1):

                                 

Cash flows provided by operating activities

    29,409       174,040                    

Cash flows used in investing activities

    (15,811 )     (364,992 )                  

Cash flows provided by financing activities

    1,048       223,720                    

Distributions received from unconsolidated affiliates

    16,932       21,838                    

Equity in income from unconsolidated affiliates

    (14,867 )     (8,279 )                  

Gross operating margin

    131,141       275,214        269,343        269,343  

EBITDA

    76,109       172,151        173,050        173,050  

Operating Data (1):

                                 

Offshore Pipelines & Services, net:

                                 

Natural gas transportation volumes (BBtus/d)

    429       1,851                    

Crude oil transportation volumes (MBbls/d)

            121                    

Platform gas treating (BBtus/d)

            316                    

Platform oil treating (MBbls/d)

            8                    

Onshore Natural Gas Pipelines & Services, net:

                                 

Natural gas transportation volumes (BBtus/d)

    646       5,746                    

NGL Pipelines & Services, net:

                                 

NGL transportation volumes (MBbls/d)

    1,368       1,394                    

NGL fractionation volumes (MBbls/d)

    229       338                    

Equity NGL production (MBbls/d)

    48       100                    

Fee-based natural gas processing volumes (MMcf/d)

    362       2,018                    

Petrochemical Services, net:

                                 

Butane isomerization volumes (MBbls/d)

    60       66                    

Propylene fractionation volumes (MBbls/d)

    54       67                    

Octane additive production volumes (MBbls/d)

    5                            

Petrochemical transportation volumes (MBbls/d)

    63       74                    

 

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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 summary historical and pro forma financial data for Enterprise Products GP and Enterprise GP Holdings. For a description of the non-GAAP financial measures that we use in this prospectus and reconciliations of these non-GAAP financial measures to their most directly comparable financial measure or measures calculated and presented in accordance with GAAP, please read “Summary—Non-GAAP Financial Measures.”

 

The following information is provided to highlight significant trends and other information regarding the historical operating results, financial position and other financial data of Enterprise Products GP. Each section below represents a footnote to the tables on the two previous pages.

 

(1) In general, Enterprise Products GP’s historical consolidated operating results and financial position have been affected by numerous acquisitions since 2000. Enterprise Products Partners’ most significant transaction to date was the merger with GulfTerra Energy Partners, L.P. and the related transactions, which were completed on September 30, 2004. The aggregate value of total consideration paid or issued by Enterprise Products Partners to complete the GulfTerra merger was approximately $4 billion. The GulfTerra merger and Enterprise Products Partners’ other acquisitions were accounted for using purchase accounting; therefore, the operating results of these acquired entities are included in Enterprise Products GP’s financial results prospectively from their respective purchase dates.

 

(2) Minority interest represents ownership interests of third-party joint venture partners and non-affiliates of Enterprise Product GP and related party ownership interests of EPCO and its controlled affiliates in the net assets and earnings of certain subsidiaries of Enterprise GP Holdings. The primary group of minority interest holders reflected in the historical financial information of Enterprise Products GP consists of the third-party and related party owners of the common units of Enterprise Products Partners. Minority interest Enterprise Products GP’s consolidated earnings and net assets has increased over time as a result of equity offerings and merger-related issuances of common units of Enterprise Products Partners. Please read Note 10, “Minority Interest,” of the Notes to Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

(3) In general, the balances of Enterprise Products GP’s consolidated long-term and current maturities of debt have increased over time as a result of financing all or a portion of the acquisitions.

 

(4) Members’ equity of Enterprise Products GP increased in 2004 as a result of contributions related to the GulfTerra merger.

 

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

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

You should read the following discussion of our financial condition and results of operations in conjunction with the historical and pro forma consolidated financial statements and notes thereto included elsewhere in this prospectus. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the historical and pro forma financial statements included elsewhere in this prospectus. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding certain risks inherent in our and Enterprise Products Partners’ business.

 

Overview

 

Financial Presentation. Since we control Enterprise Products GP, we reflect our ownership interest in Enterprise Products Partners on a consolidated basis, which means that our financial results are combined with Enterprise Products GP’s and Enterprise Products Partners’ financial results. The limited partner interests in Enterprise Products Partners not owned by controlled affiliates of Enterprise Products GP are reflected as minority interest expense in our results of operations. We currently have no separate operating activities apart from those conducted by Enterprise Products Partners, and, initially, our operating cash flow will be derived primarily from cash distributions from Enterprise Products Partners. Our consolidated financial statements do not differ materially from the results of operations of Enterprise Products Partners. The number and dollar amount of reconciling items between our consolidated financial statements and those of Enterprise Products Partners are insignificant. Accordingly, the discussion of our financial position and results of operations in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” reflects the operating activities and results of operations of Enterprise Products Partners. The historical results of operations do not reflect incremental general and administrative expenses we expect to incur, including those resulting from being a public company, which we expect to be approximately $3 million per year.

 

General. We are the sole member of Enterprise Products GP, which is the general partner of Enterprise Products Partners. Enterprise Products Partners is a leading North American midstream energy company providing a wide range of services to producers and consumers of natural gas, NGLs and crude oil, and is an industry leader in the development of pipeline and other midstream infrastructure in the continental United States and deepwater trend of the Gulf of Mexico. Enterprise Products Partners conducts substantially all of its business through its operating partnership and wholly owned subsidiary, Enterprise Products Operating L.P., which we refer to as the Operating Partnership. Enterprise Products Partners is owned 98% by its limited partners and 2% by Enterprise Products GP.

 

Our assets consist of the following partnership interests in Enterprise Products Partners contributed to us by EPCO:

 

    a 100% ownership of Enterprise Products GP, which owns a 2% general partner interest in Enterprise Products Partners that entitles us to receive 2% of the cash distributed by Enterprise Products Partners;

 

    the incentive distribution rights associated with Enterprise Products Partners’ general partner interest, which entitle us to receive increasing percentages of the cash distributed by Enterprise Products Partners (up to a maximum of 25%) as Enterprise Products Partners’ per unit distribution increases; and

 

    13,454,498 common units of Enterprise Products Partners, representing an approximate 3.4% limited partner interest in Enterprise Products Partners.

 

Because the incentive distribution rights currently participate at the maximum 25% sharing level (inclusive of the 2% general partner interest and associated incentive distribution rights) in all distributions made by Enterprise Products Partners above $0.3085 per unit, future growth in distributions we receive from Enterprise Products Partners will not result from an increase in the sharing level associated with the incentive distribution rights. Please read “Enterprise Products Partners’ Cash Distribution Policy—Incentive Distributions.”

 

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Since its initial public offering in 1998, Enterprise Products Partners has increased its quarterly distribution by approximately 87%, from $0.225 per unit, or $0.90 per unit on an annualized basis, to $0.42 per unit, or $1.68 per unit on an annualized basis. Based upon Enterprise Products Partners’ recently announced quarterly distribution of $0.42 per unit declared and payable with respect to the second quarter of 2005 and the number of its common units outstanding at July 15, 2005, we would have been entitled to receive a quarterly cash distribution of approximately $25.7 million (or approximately $102.8 million on an annualized basis), consisting of $3.3 million from Enterprise Products GP’s 2% general partner interest, $16.7 million from the associated incentive distribution rights and $5.7 million from the common units of Enterprise Products Partners that we own.

 

Cash Distributions. The following table sets forth the distributions that Enterprise Products Partners has paid in respect of the 2% general partner interest, the associated incentive distribution rights and 13,454,498 common units during the periods indicated. We will not distribute all of the cash that we receive from Enterprise Products Partners to our unitholders, as our general partner will establish reserves for debt service requirements, general, administrative and other expenses, future distributions and other miscellaneous uses of cash.

 

     For the Year Ended December 31,

 
     2000

   2001

    2002

    2003

    2004

 
     (In millions, except per unit amounts)  

Selected Cash Distribution Data:

        

Cash distribution per unit paid by Enterprise Products Partners

   $ 1.03    $ 1.16     $ 1.33     $ 1.44     $ 1.51  
    

  


 


 


 


Average number of Enterprise Products Partners distribution-bearing units outstanding

     134.4      138.4       153.1       198.1       259.9  
    

  


 


 


 


Cash distributions paid to Enterprise Products GP by Enterprise Products Partners:

                                       

From 2% general partner interest

   $ 2.8    $ 3.3     $ 4.3     $ 6.0     $ 8.1  

From associated incentive distribution rights

     0.4      3.2       9.8       19.7       32.4  
    

  


 


 


 


Total distributions paid to Enterprise Products GP

     3.2      6.5       14.1       25.7       40.5  

Cash distributions paid by Enterprise Products Partners on 13,454,498 of its common units

     13.8      15.6       17.9       19.4       20.3  
    

  


 


 


 


Total cash distributions

   $ 17.0    $ 22.1     $ 32.0     $ 45.1     $ 60.8  
    

  


 


 


 


Percentage growth in total distributions over previous year

     —        30.0 %     44.8 %     40.9 %     34.8 %

 

From 2000 through 2004, the aggregate annual cash distributions made by Enterprise Products Partners in respect of all of its partnership interests increased 209%, from approximately $141.0 million to approximately $435.8 million. Over the same period, the aggregate annual cash distributions made by Enterprise Products Partners in respect of our partnership interests increased 258%, from $17.0 million, or 12.1% of Enterprise Products Partners’ aggregate annual distributions, to $60.8 million, or 14.0% of Enterprise Products Partners’ aggregate annual distributions. The increase in historical cash distributions on our partnership interests generally resulted from the following:

 

    the increase in Enterprise Products Partners’ per unit quarterly distribution from $0.25 declared and paid in the first quarter of 2000 to $0.42 declared and payable in the third quarter of 2005; and

 

    the issuance of approximately 250 million additional units by Enterprise Products Partners during such period to finance acquisitions and capital improvements.

 

Recent Developments

 

GulfTerra Merger . On September 30, 2004, Enterprise Products Partners and GulfTerra Energy Partners, L.P., or GulfTerra, completed the merger of GulfTerra with a wholly owned subsidiary of Enterprise Products

 

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Partners, with GulfTerra being the surviving entity thereof. Additionally, Enterprise Products Partners completed certain other transactions related to the merger, including the receipt of Enterprise Products GP’s contribution of a 50% membership interest in GulfTerra’s general partner, which was acquired by Enterprise Products GP from El Paso Corporation, and the purchase of certain midstream energy assets located in South Texas from El Paso Corporation, which are referred to herein as the South Texas midstream assets. The aggregate value of the total consideration Enterprise Products Partners paid or issued to complete the GulfTerra merger was approximately $4 billion.

 

As a result of the GulfTerra merger, GulfTerra and its general partner became wholly owned subsidiaries of Enterprise Products Partners on September 30, 2004. On October 1, 2004, Enterprise Products Partners contributed its ownership interests in GulfTerra and GulfTerra’s general partner to the Operating Partnership, which resulted in GulfTerra and its general partner becoming wholly owned subsidiaries of the Operating Partnership.

 

Formed in 1993, GulfTerra manages a balanced, diversified portfolio of interests and assets relating to the midstream energy sector, which involves gathering, transporting, separating, processing, fractionating and storing natural gas, oil and NGLs. GulfTerra’s interests and assets included (i) offshore oil and natural gas pipelines, platforms, processing facilities and other energy infrastructure in the Gulf of Mexico, primarily offshore Louisiana and Texas; (ii) onshore natural gas pipelines and processing facilities in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas; (iii) onshore NGL pipelines and fractionation facilities in Texas; and (iv) onshore natural gas and NGL storage facilities in Louisiana, Mississippi and Texas.

 

The South Texas midstream assets consisted of nine natural gas processing plants with a combined capacity of 1.9 billion cubic feet per day, or Bcf/d, a 294-mile natural gas gathering system, a natural gas treating facility with a capacity of 150 million cubic feet per day, or MMcf/d, and a small NGL pipeline.

 

The GulfTerra merger occurred in several interrelated transactions as described below.

 

    Step one . On December 15, 2003, Enterprise Products Partners purchased a 50% membership interest in GulfTerra’s general partner from El Paso Corporation for $425 million in cash. GulfTerra’s general partner owns a 1% general partner interest in GulfTerra. Prior to completion of the GulfTerra merger, Enterprise Products Partners accounted for its investment in GulfTerra’s general partner using the equity method of accounting. The $425 million in funds required to complete step one were borrowed under an interim term loan and the Operating Partnership’s pre-merger revolving credit facilities. This amount was fully repaid with the net proceeds from Enterprise Products Partners’ equity offerings completed during 2004.

 

    Step two . On September 30, 2004, the GulfTerra merger was consummated, and GulfTerra and its general partner became wholly owned subsidiaries of Enterprise Products Partners. The GulfTerra merger was accounted for using purchase accounting. Step two of the GulfTerra merger included the following transactions:

 

    Immediately prior to closing the GulfTerra merger, Enterprise Products GP acquired El Paso Corporation’s remaining 50% membership interest in GulfTerra’s general partner for $370 million in cash paid to El Paso Corporation and the issuance of a 9.9% membership interest in Enterprise Products GP to El Paso Corporation. Subsequently, Enterprise Products GP contributed this 50% membership interest in GulfTerra’s general partner to Enterprise Products Partners without the receipt of additional general partner interest, common units or other consideration. Enterprise Products GP borrowed the foregoing $370 million from Dan Duncan LLC (which owns a membership interest in Enterprise Products GP), which obtained the funds from a loan from EPCO (which indirectly owns the remaining membership interests in Enterprise Products GP).

 

   

Immediately prior to closing the GulfTerra merger, Enterprise Products Partners paid $500 million in cash to El Paso Corporation for 10,937,500 Series C units of GulfTerra and 2,876,620 common

 

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units of GulfTerra. The remaining 57,762,369 GulfTerra common units (7,433,425 of which were owned by El Paso Corporation) were converted into 104,549,823 Enterprise common units (13,454,498 of which are held by El Paso Corporation) at the time of the consummation of the GulfTerra merger.

 

    Step three . Immediately after Step Two was completed, the Operating Partnership acquired certain South Texas midstream assets from El Paso Corporation for $155.3 million in cash. Pursuant to written agreements, the Operating Partnership’s purchase of the South Texas midstream assets was effective September 1, 2004.

 

In connection with the closing of the GulfTerra merger, on September 30, 2004, the Operating Partnership borrowed an aggregate $2.8 billion under its new revolving credit facilities to fund its cash payment obligations under step two and step three of the GulfTerra merger and related transactions, including the tender offers for GulfTerra’s outstanding senior and senior subordinated notes.

 

In connection with the GulfTerra merger, Enterprise Products Partners was required under a consent decree to sell its 50% interest in Starfish Pipeline Company, LLC, or Starfish, which owns the Stingray natural gas pipeline and related gathering pipelines and dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana by March 31, 2005. In January 2005, Enterprise Products Partners entered into a contract with a third party to sell this investment for approximately $42.1 million. Enterprise Products Partners closed this sale on March 31, 2005 following the receipt of FTC approval under the terms of the consent decree relating to the GulfTerra merger. Additionally, under the same consent decree, Enterprise Products Partners was required to sell its undivided 50% interest in a Mississippi propane storage facility by December 31, 2004. Enterprise Products Partners sold its interest in this facility during the fourth quarter of 2004.

 

For additional information regarding the GulfTerra merger and Enterprise Products Partners’ other business combinations and asset acquisitions completed during 2004 (including selected pro forma financial information), please read the Notes to Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Acquisition of El Paso’s Interests in Enterprise Products Partners and Enterprise Products GP by an Affiliate of EPCO . In January 2005, an affiliate of EPCO acquired a 9.9% membership interest in Enterprise Products GP and 13,454,498 common units of Enterprise Products Partners from El Paso Corporation for approximately $425 million in cash. As a result of these transactions, affiliates of EPCO owned 100% of the membership interests of Enterprise Products GP. El Paso Corporation no longer owns any interest in Enterprise Products Partners or Enterprise Products GP.

 

Agreement with Atwater Valley Producers Group for Deepwater Platform and Gas Pipeline . In November 2004, Enterprise Products Partners entered into an agreement with the Atwater Valley Producers Group (consisting of Anadarko Petroleum Corporation, Dominion Resources, Inc., Kerr-McGee Corporation, Spinnaker Exploration Co. and Devon Energy Corporation) for the dedication, processing and gathering of natural gas and condensate production from several natural gas fields in the Atwater Valley, DeSoto Canyon and Lloyd Ridge areas of the deepwater Gulf of Mexico. Enterprise Products Partners will design, construct, install and own Independence Hub, a 105-foot deep-draft, semi-submersible platform with a two-level production deck, which will be capable of processing 850 MMcf/d of natural gas. The platform, which is estimated to cost approximately $385 million, will be operated by Anadarko. Cal Dive International, Inc. is Enterprise Products Partners’ 20% joint venture partner in the Independence Hub Platform project. Additionally, Enterprise Products Partners will construct, own, and operate the 134-mile Independence Trail natural gas pipeline system, which will have a throughput capacity of approximately 850 MMcf/d of natural gas. The pipeline system, which is estimated to cost $280 million, will transport production from the Independence Hub platform to the Tennessee Gas Pipeline.

 

Rocky Mountain NGL Pipeline Expansion and Related NGL Fractionation Projects . In January 2005, Enterprise Products Partners started a project to expand its Mont Belvieu NGL fractionator to accommodate

 

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increased production of NGLs being transported to Mont Belvieu, Texas from the Rocky Mountain area. Enterprise Products Partners’ Mont Belvieu facility’s current fractionation capacity is up to 210 thousand barrels per day, or MBbls/d, of mixed NGLs. This project, which is expected to be completed in the first quarter of 2006 at an estimated total cost of $34.2 million, will increase total fractionation capacity at this facility by 15 MBbls/d and reduce its energy costs. Additionally, Enterprise Products Partners has announced that it plans to construct a new NGL fractionator, designed to handle up to 75 MBbls/d of mixed NGLs, located at the interconnection of the Mid-America pipeline system and the Seminole pipeline system near Hobbs, New Mexico.

 

Currently, the Rocky Mountain segment of Enterprise Products Partners’ Mid-America pipeline system transports up to 225 MBbls/d of NGLs from the major producing basins in Wyoming, Utah, Colorado and New Mexico to the Hobbs station on the Texas-New Mexico border. The Western Expansion Project would increase the capacity of this pipeline to 275 MBbls/d. Permitting, engineering and design work are in progress. Enterprise Products Partners submitted a draft environmental assessment and plan of development to the appropriate regulatory agencies during the first quarter of 2005. Contingent upon receiving all required permits and regulatory approvals, construction could begin as early as the fourth quarter of 2005.

 

Acquisition of Indian Springs Natural Gas Gathering and Processing Assets from El Paso . In January 2005, Enterprise Products Partners paid El Paso Corporation $74.5 million for its membership interests in Teco Gas Gathering, LLC and Teco Gas Processing, LLC. As a result of this acquisition, Enterprise Products Partners indirectly owns an 80% equity interest in the 89-mile Indian Springs Gathering System and a 75% equity interest in the Indian Springs natural gas processing facility, both of which are located in East Texas. The Indian Springs processing facility has capacity to process up to 120 MMcf/d of natural gas, and there is an idle 20 MMcf/d production train available for restart to support increases in natural gas volumes. The natural gas processed at the Indian Springs processing facility is sourced from the Indian Springs Gathering System, as well as Enterprise Products Partners’ nearby Big Thicket Gathering System.

 

Acquisition of Additional Interests in Dixie Pipeline Company . Enterprise Products Partners purchased an approximate 26% interest in Dixie Pipeline Company, or Dixie, from an affiliate of ChevronTexaco Corporation in February 2005 for $40 million, and an approximate 20% interest in Dixie from an affiliate of ConocoPhillips in January 2005 for $31 million. As a result of these acquisitions, Enterprise Products Partners’ ownership interest in Dixie is now approximately 66%, and Dixie will be a consolidated subsidiary. The other owners of Dixie are affiliates of BP p.l.c., or BP, with a 23% interest and ExxonMobil Corporation with an 11% interest. Dixie owns and operates the 1,301-mile Dixie Pipeline, which is a pipeline that transports propane from supply areas in Texas, Louisiana and Mississippi to markets throughout the southeastern United States. The Dixie Pipeline is regulated by the FERC and transports an average of approximately 100 MBbls/d of propane.

 

Non-Public Investigation by the Bureau of Competition of the Federal Trade Commission . On February 24, 2005, an affiliate of EPCO acquired TEPPCO GP from Duke Energy Field Services, LLC. TEPPCO GP owns a 2% general partner interest in and is the general partner of TEPPCO Partners. On March 11, 2005, the Bureau of Competition of the Federal Trade Commission delivered written notice to this affiliate’s legal advisor that it was conducting a non-public investigation to determine whether this affiliate’s acquisition of TEPPCO GP may substantially lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with the purchase of TEPPCO GP. EPCO and its affiliates may receive similar inquiries from other regulatory authorities. We intend to cooperate fully with any such investigations and inquiries.

 

Construction of New NGL Fractionator at Hobbs, New Mexico . In June 2005, Enterprise Products Partners announced plans to construct an NGL fractionator to be located at the interconnection of the Mid-America Pipeline System and the Seminole Pipeline System near Hobbs, New Mexico. The fractionator will handle up to 75,000 barrels per day of mixed NGLs, which will be sourced from current and future processing plants in the Rocky Mountain region, the Permian Basin, and in the Panhandle area of Texas and Oklahoma on the Mid-America Pipeline. Additionally, Enterprise Products Partners will construct a purity ethane storage well near the new fractionator and reconfigure the interconnection between the Mid-America Pipeline and the Seminole Pipeline. The projected cost is approximately $130 million. This project is expected to be in operation by mid-2007.

 

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Upon completion, the Hobbs fractionator will have access to the NGL market in the United States at Mont Belvieu, Texas through Seminole, as well as the NGL market located at Conway, Kansas. Enterprise Products Partners will also have access to NGL consumers in the upper Midwest through Mid-America, and a growing local market that includes nearby refineries that consume NGLs as a blend stock to produce motor gasoline and increased propane demand in northern Mexico. This site adds fractionation capacity at a location that reduces the volume of mixed NGLs that Enterprise Products Partners may transport to Mont Belvieu on third party pipelines due to capacity constraints on Seminole, increases available capacity on Seminole and reduces the volumes Enterprise Products Partners may offload to third party fractionators in the Mont Belvieu area.

 

Investments in NGL Assets . In June 2005, Enterprise Products Partners announced that it will make additional investments to expand its integrated network of NGL assets in the Permian basin and Mid-Continent region of the United States. Enterprise Products Partners executed an agreement to acquire three NGL underground storage facilities and four propane terminals from Ferrellgas, L.P., a subsidiary of Ferrellgas Partners, L.P., for a purchase price of $144 million. The asset purchase is expected to close in the third quarter of 2005, subject to regulatory approval and other customary conditions to closing. The underground storage facilities, located in Kansas, Arizona and Utah, have a combined capacity of 6.1 million barrels, approximately 70% of which is leased to third party customers under fee-based contracts. The four propane terminals are located in Minnesota and North Carolina and provide above-ground storage and delivery facilities to multi-state and independent retailers and regional end-users in the area.

 

In addition, Enterprise Products Partners has begun engineering and design work to expand its Mid-America Pipeline by constructing a 190-mile, 12-inch NGL pipeline that will have the capacity to move up to 67,000 barrels per day of mixed NGLs bi-directionally between Skellytown, Texas and Conway, Kansas and an additional 35,000 barrels per day from Skellytown to Hobbs, New Mexico. Construction of the pipeline will begin in mid-2006 and is expected to be in service in the first quarter of 2007.

 

Enterprise Products Partners also has exercised its option to acquire from an affiliate of Williams Companies, Inc. a 2.0% indirect ownership interest in the Mid-America Pipeline and a 1.6% indirect ownership interest in the Seminole Pipeline for a total purchase price of $25 million. This transaction was completed on June 30, 2005, and as a result, Enterprise Products Partners owns 100% of the Mid-America Pipeline and 90% of the Seminole Pipeline.

 

Results of Operations

 

As a result of completing the GulfTerra merger on September 30, 2004, Enterprise Products Partners’ Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2004 include three months of results of operations from the GulfTerra assets. The effective closing date of the Operating Partnership’s purchase of the South Texas midstream assets was September 1, 2004; thus, Enterprise Products Partners’ Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2004 include four months of results of operations from the South Texas midstream assets.

 

As a result of the GulfTerra merger, Enterprise Products Partners reorganized its reportable business segments, as described below. Enterprise Products Partners also revised its prior segment information in order to conform to the current business segment operations and presentation.

 

Enterprise Products Partners has four reportable business segments: (i) Offshore Pipelines & Services, (ii) Onshore Natural Gas Pipelines & Services, (iii) NGL Pipelines & Services, and (iv) Petrochemical Services. Enterprise Products Partners’ business segments are generally organized and managed along its midstream asset base according to the type of services rendered (or technology employed) and products produced and sold. For a listing of the major components of each of Enterprise Products Partners’ four business segments, and the principal operating assets included within each of the major components, please read the Notes to Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

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Offshore Pipelines & Services . The Offshore Pipelines & Services business segment consists of (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 800 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico, which are included in Enterprise Products Partners’ Offshore Pipelines & Services business segment.

 

Onshore Natural Gas Pipelines & Services. The Onshore Natural Gas Pipelines & Services business segment consists of approximately 17,200 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, this segment includes two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast domestic natural gas markets. This segment also includes leased natural gas storage facilities located in Texas and Louisiana.

 

NGL Pipelines & Services . The NGL Pipelines & Services business segment includes Enterprise Products Partners’ (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,775 miles and related storage facilities, which include Enterprise Products Partners’ strategic Mid-America and Seminole NGL pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes Enterprise Products Partners’ import and export terminaling operations.

 

Petrochemical Services . The Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex, and an octane additive production facility. This segment also includes various petrochemical pipeline systems.

 

The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings Enterprise Products Partners received from GulfTerra’s general partner and its underlying investment in this entity at December 31, 2003. Enterprise Products Partners acquired a 50% membership interest in GulfTerra’s general partner on December 15, 2003 in connection with step one of the GulfTerra merger. Enterprise Products Partners’ investment in GulfTerra’s general partner was accounted for using the equity method until the GulfTerra merger was completed on September 30, 2004. On that date, GulfTerra’s general partner became a wholly owned consolidated subsidiary of Enterprise Products Partners. Since the historical equity earnings of GulfTerra’s general partner were based on net income amounts allocated to it by GulfTerra, it is impractical for Enterprise Products Partners to allocate the equity income it received during the periods presented to each of its new business segments. Therefore, Enterprise Products Partners has segregated equity earnings from GulfTerra’s general partner from its other segment results to aid in comparability between the periods presented.

 

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

 

Enterprise Products Partners defines total (or consolidated) segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which it does not have the payment obligation; (3) gains and losses on the sale of assets; and (4) general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income

 

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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 intercompany transactions.

 

Enterprise Products Partners has historically included equity earnings from unconsolidated affiliates in its measurement of segment gross operating margin and operating income. Enterprise Products Partners equity investments with industry partners are a vital component of its business strategy. They are a means by which Enterprise Products Partners conducts its operations to align its interests with those of its customers, which may be suppliers of raw materials or consumers of finished products. This method of operation also enables Enterprise Products Partners to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what it could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to Enterprise Products Partners’ other business operations.

 

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

 

Many of Enterprise Products Partners’ equity investees are present within its integrated midstream asset system. For example, Enterprise Products Partners has ownership interests in several offshore natural gas and crude oil pipelines through its investments in Poseidon Oil Pipeline Company, L.L.C., Cameron Highway Oil Pipeline Company, Deepwater Gateway, L.L.C., Neptune Pipeline Company, L.L.C. and Nemo Gathering Company, L.L.C. Enterprise Products Partners also has a number of investments in NGL transportation or distribution pipelines such as those owned by Belle Rose NGL Pipeline LLC and Dixie (prior to its purchasing consolidating interests in Dixie in January and February 2005). Other examples include Enterprise Products Partners’ use of the K/D/S Promix LLC, or Promix, NGL fractionator to process NGLs extracted by its gas plants. The NGLs received from Promix then can be sold in its NGL marketing activities. Given the integral nature of its equity investees to its operations, Enterprise Products Partners believes treatment of earnings from its equity method investees as a component of gross operating margin and operating income is appropriate.

 

For additional information regarding Enterprise Products Partners’ investments in and advances to unconsolidated affiliates, please read the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus. For additional information regarding Enterprise Products Partners’ business segments, please read the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

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

 

    Year Ended December 31,

 

For the Three Months

Ended March 31,


    2004

  2003

    2002

  2005

  2004

Onshore Natural Gas Pipelines & Services

  $ 90,977   $ 18,345     $ 22,110   $ 23,224   $ 982

NGL Pipelines & Services

    374,196     310,677       181,928     79,358     5,599

Petrochemical Services

    121,515     75,885       117,776     153,304     89,955

Offshore Pipeline & Services

    36,478     5,561       10,535     19,328     24,051

Other, non-segment

    32,025     (53 )     —       —       10,554
   

 


 

 

 

Total segment gross operating margin

  $ 655,191   $ 410,415     $ 332,349   $ 275,214   $ 131,141
   

 


 

 

 

 

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For a reconciliation of non-GAAP gross operating margin to GAAP operating income and further to GAAP income before provision for taxes, minority interest and the cumulative effect of changes in accounting principles, please read “—Other Items.”

 

Selected Price and Volumetric Information

 

The following table illustrates selected average quarterly industry index prices for natural gas, crude oil, selected NGL and petrochemical products and indicative gas processing gross spreads since the beginning of 2002:

 

   

Natural
Gas,

$/MMBtu


 

Crude
Oil,

$/barrel


 

Ethane,

$/gallon


  Propane,
$/gallon


  Normal
Butane,
$/gallon


  Isobutane,
$/gallon


  Natural
Gasoline,
$/gallon


  Polymer
Grade
Propylene,
$/pound


  Refinery
Grade
Propylene,
$/pound


 

Indicative
Gas
Processing
Gross
Spread,

$/gallon


    (1)   (2)   (1)   (1)   (1)   (1)   (1)   (1)   (1)   (3)

2002

                                                           

1st Quarter

  $ 2.34   $ 21.41   $ 0.22   $ 0.30   $ 0.38   $ 0.44   $ 0.47   $ 0.16   $ 0.12   $ 0.12

2nd Quarter

  $ 3.38   $ 26.26   $ 0.26   $ 0.40   $ 0.48   $ 0.51   $ 0.58   $ 0.20   $ 0.17   $ 0.10

3rd Quarter

  $ 3.16   $ 28.30   $ 0.26   $ 0.42   $ 0.52   $ 0.58   $ 0.61   $ 0.21   $ 0.16   $ 0.14

4th Quarter

  $ 3.99   $ 28.33   $ 0.31   $ 0.49   $ 0.60   $ 0.63   $ 0.66   $ 0.20   $ 0.15   $ 0.13
   

 

 

 

 

 

 

 

 

 

Average for Year

  $ 3.22   $ 26.08   $ 0.26   $ 0.40   $ 0.50   $ 0.54   $ 0.58   $ 0.20   $ 0.15   $ 0.12

2003

                                                           

1st Quarter

  $ 6.58   $ 34.12   $ 0.43   $ 0.65   $ 0.76   $ 0.80   $ 0.85   $ 0.24   $ 0.21   $ 0.05

2nd Quarter

  $ 5.40   $ 29.04   $ 0.39   $ 0.53   $ 0.58   $ 0.62   $ 0.65   $ 0.25   $ 0.19   $ 0.04

3rd Quarter

  $ 4.97   $ 30.21   $ 0.37   $ 0.56   $ 0.67   $ 0.68   $ 0.73   $ 0.21   $ 0.15   $ 0.10

4th Quarter

  $ 4.58   $ 31.18   $ 0.40   $ 0.58   $ 0.73   $ 0.71   $ 0.75   $ 0.22   $ 0.16   $ 0.17
   

 

 

 

 

 

 

 

 

 

Average for Year

  $ 5.38   $ 31.14   $ 0.40   $ 0.58   $ 0.68   $ 0.70   $ 0.74   $ 0.23   $ 0.18   $ 0.09

2004

                                                           

1st Quarter

  $ 5.69   $ 35.25   $ 0.43   $ 0.66   $ 0.76   $ 0.76   $ 0.87   $ 0.29   $ 0.26   $ 0.13

2nd Quarter

  $ 6.00   $ 38.34   $ 0.45   $ 0.65   $ 0.79   $ 0.79   $ 0.92   $ 0.32   $ 0.26   $ 0.12

3rd Quarter

  $ 5.75   $ 43.90   $ 0.52   $ 0.79   $ 0.92   $ 0.92   $ 1.05   $ 0.32   $ 0.27   $ 0.26

4th Quarter

  $ 7.07   $ 48.31   $ 0.60   $ 0.85   $ 1.03   $ 1.04   $ 1.15   $ 0.40   $ 0.35   $ 0.22
   

 

 

 

 

 

 

 

 

 

Average for Year

  $ 6.13   $ 41.45   $ 0.50   $ 0.74   $ 0.88   $ 0.88   $ 1.00   $ 0.33   $ 0.29   $ 0.18

200 5

                                                           

1st Quarter

  $ 6.27   $ 49.68   $ 0.52   $ 0.79   $ 0.98   $ 1.00   $ 1.14   $ 0.45   $ 0.39   $ 0.24

(1) Natural gas, NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including Oil Price Information Service, or OPIS, and Chemical Market Associates, Inc., or CMAI. Natural gas price is representative of Henry-Hub I-FERC. NGL prices are representative of Mont Belvieu Non-TET pricing. Refinery grade propylene represents an average of CMAI spot prices. Polymer-grade propylene represents average CMAI contract pricing.
(2) Crude oil price is representative of an index price for West Texas Intermediate.
(3) The Indicative Gas Processing Gross Spread is a relative measure used by the NGL industry as an indicator of the gross economic benefit derived from extracting NGLs from natural gas production on the U.S. Gulf Coast. Specifically, it is the amount by which the economic value of a composite gallon of NGLs exceeds the value of the equivalent amount of energy of natural gas based on NGL and natural gas prices on the U.S. Gulf Coast. It is assumed that a gallon of NGLs is comprised of 33% ethane, 32% propane, 11% normal butane, 8% isobutane and 16% natural gasoline. The value of a composite gallon of NGLs is determined by multiplying these component percentages by industry index prices listed in the table above. The value of the equivalent amount of energy of natural gas to one gallon of NGLs is 8.9% of the price of a MMBtu of natural gas. The Indicative Gas Processing Gross Spread does not consider the operating and fuel costs incurred by a natural gas processing plant to extract the NGLs nor the transportation and fractionation costs to deliver the NGLs and natural gas to market.

 

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Enterprise Products Partners’ significant throughput, production and processing volumetric data were as follows for the periods indicated (on a net basis, taking into account its ownership interests):

 

    For Year Ended December 31,

 

For the Three Months

Ended March 31,


        2004(1)    

      2003(1)    

      2002(1)    

  2005(1)

  2004(1)

Offshore Pipelines & Services, net:

                   

Natural gas transportation volumes (BBtus/d)(2)

  2,081   433   500   1,851   429

Crude oil transportation volumes (MBbls/d)

  138           121    

Platform gas treating (BBtus/d)

  306           316    

Platform oil treating (MBbls/d)

  14           8    

Onshore Natural Gas Pipelines & Services, net:

                   

Natural gas transportation volumes (BBtus/d)

  5,638   600   701   5,746   646

NGL Pipelines & Services, net:

                   

NGL transportation volumes (MBbls/d)

  1,411   1,275   1,306   1,394   1,368

NGL fractionation volumes (MBbls/d)

  307   227   235   338   229

Equity NGL production (MBbls/d)

  129   43   73   100   48

Fee-based natural gas processing (MMcf/d)(3)

  1,692   194       2,018   362

Petrochemical Services, net:

                   

Butane isomerization volumes (MBbls/d)

  76   77   84   66   60

Propylene fractionation volumes (MBbls/d)

  56   57   55   67   54

Octane additive production volumes (MBbls/d)

  10   4   5       5

Petrochemical transportation volumes (MBbls/d)

  71   68   46   74   63

Total, net:

                   

NGL, crude oil and petrochemical transportation volumes (MBbls/d)

  1,620   1,343   1,352   1,589   1,431

Natural gas transportation volumes (BBtus/d)

  7,719   1,033   1,201   7,597   1,075

Equivalent transportation volumes (MBbls/d)(4)

  3,651   1,615   1,668   3,588   1,714

(1) Volumetric data shown above reflects net operating rates of the underlying assets for the periods in which Enterprise Products Partners owned them.
(2) Excludes fourth quarter of 2004 and first quarter of 2005 volumes for Starfish, which Enterprise Products Partners is prohibited from obtaining under an FTC consent decree published for comment on September 30, 2004.
(3) Fee-based natural gas processing volumes increases reflect amendments to Enterprise Products Partners’ natural gas processing contract mix that were completed during the first quarter of 2004.
(4) Reflects equivalent energy volumes where 3.8 million British thermal units, or MMBtus, of natural gas are equivalent to one barrel of NGLs.

 

The following table summarizes Enterprise Products Partners’ key components of results of operations for the periods indicated:

 

     For the Year Ended December 31,

   For the Three Months Ended
March 31,


     2004

   2003

    2002

   2005

   2004

     (In thousands)

Revenues

   $ 8,321,202    $ 5,346,431     $ 3,584,783    $ 2,555,522    $ 1,704,890

Operating costs and expenses

     7,904,336      5,046,777       3,382,839      2,383,644      1,621,508

General and administrative costs

     46,659      37,590       42,890      14,693      9,466

Equity in income (loss) of unconsolidated affiliates

     52,787      (13,960 )     35,253      8,279      14,867

Operating income

     422,994      248,104       194,307      165,464      88,783

Interest expense

     155,740      140,806       101,580      53,413      32,618

Net income

     268,261      104,546       95,500      109,256      62,528

 

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Revenues from the sale and marketing of NGL products within the NGL Pipelines & Services business segment accounted for 67%, 68% and 65% of total consolidated revenues for the years ended December 31, 2004, 2003 and 2002, respectively. Revenues from the sale of petrochemical products within the Petrochemical Services segment accounted for 13%, 12% and 14% of total consolidated revenues for the years ended December 31, 2004, 2003 and 2002, respectively. Revenues from the onshore transportation of natural gas accounted for 11% and 12% of total consolidated revenues for the years ended December 31, 2003 and 2002.

 

Revenues from the sale and marketing of NGL products within the NGL Pipelines & Services business segment accounted for 67% and 71% of total consolidated revenues for the three months ended March 31, 2005 and 2004, respectively. Revenues from the sale of petrochemical products within the Petrochemical Services segment accounted for 13% and 12% of total consolidated revenues for the three months ended March 31, 2005 and 2004, respectively. Revenues from onshore transportation and storage of natural gas accounted for 12% of total consolidated revenues for the three months ended March 31, 2005.

 

Comparison of Three Months Ended March 31, 2005 with Three Months Ended March 31, 2004

 

In general, an increase in Enterprise Products Partners’ revenues and costs and expenses quarter-to-quarter is attributable to the results of businesses acquired or consolidated since March 31, 2004. In addition, higher energy commodity prices result in increased revenues from Enterprise Products Partners’ NGL and petrochemical marketing activities; however, these same higher prices also increase its cost of sales within these activities as feedstock and other related purchase prices rise. For selected general energy commodity price information and detailed segment-level volumetric information, please review the tables under “—Selected Price and Volumetric Information.” The weighted-average market price for NGLs was 80 cents per gallon for the first three months of 2005 versus 64 cents per gallon during the same period in 2004—a quarter-to-quarter increase of 25%. Our determination of the weighted-average market price for NGLs is based on selected U.S. Gulf Coast prices for such products at Mont Belvieu, which is the primary industry hub for domestic NGL production. The market price of natural gas (as measured at Henry Hub) averaged $6.27 per MMBtu for the first three months of 2005 versus $5.69 per MMBtu during the 2004 period. Polymer grade propylene index prices increased 55% quarter-to-quarter and refinery grade propylene index prices increased 48% quarter-to-quarter.

 

Enterprise Products Partners’ revenues for the first quarter of 2005 increased $850.6 million over those recorded during the same period in 2004. In general, the trend in consolidated revenues can be attributed to (i) a $425 million increase in revenues from our NGL and petrochemical marketing activities primarily resulting from an increase in overall sales volumes and energy commodity market prices and (ii) the addition of $438 million in revenues from businesses acquired or consolidated since March 31, 2004, which primarily include GulfTerra and the South Texas midstream assets.

 

Consolidated costs and expenses increased $762.1 million quarter-to-quarter primarily due to (i) an increase in volumes purchased including the effects of higher product prices, which resulted in a $332 million increase in the cost of sales of Enterprise Products Partners’ NGL and petrochemical marketing activities and (ii) the addition of $329 million in costs and expenses attributable to businesses acquired or consolidated since March 31, 2004. Operating costs and expenses for the first quarter of 2005 were reduced by a $5.4 million gain on the sale of Enterprise Products Partners’ investment in Starfish, which was required to gain regulatory approval for the GulfTerra merger.

 

General and administrative costs also increased $5.2 million quarter-to-quarter primarily due to businesses acquired since March 31, 2004. Equity earnings from unconsolidated affiliates decreased $6.6 million quarter-to-quarter primarily due to the consolidation of GulfTerra’s general partner resulting from completion of the GulfTerra merger on September 30, 2004. Collectively, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to a $76.7 million increase in operating income quarter-to-quarter.

 

The $20.8 million increase in Enterprise Products Partners’ interest expense is primarily due to additional debt it incurred as a result of the GulfTerra merger and the Operating Partnership’s related issuance of Senior

 

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Notes E, F, G and H in October 2004 and Senior Notes I and J in February 2005. Enterprise Products Partners’ weighted-average debt principal outstanding was $4.3 billion during the first quarter of 2005 compared to $2.2 billion during the first quarter of 2004.

 

As a result of the items noted in previous paragraphs, Enterprise Products Partners’ net income increased $46.8 million to $109.3 million for the first quarter of 2005 from $62.5 million for the first quarter of 2004. The first quarter of 2004 includes a $10.8 million benefit related to the cumulative effect of changes in accounting principles adopted during 2004. For additional information regarding the cumulative effect of changes in accounting principles we recorded during 2004, please read “—Other Items.”

 

The following information highlights the significant quarter-to-quarter variances in Enterprise Products Partners’ gross operating margin by business segment. For information regarding transportation, processing and other volumetric data by segment for the three months ended March 31, 2005 and 2004, please read “—Selected Price and Volumetric Information.”

 

Offshore Pipelines & Services . Gross operating margin from this business segment increased $22.2 million quarter-to-quarter primarily due to offshore Gulf of Mexico assets Enterprise Products Partners acquired in connection with the GulfTerra merger. These assets accounted for $22.7 million of gross operating margin recorded for this segment during the first quarter of 2005.

 

Onshore Natural Gas Pipelines & Services . Gross operating margin from this business segment increased $73.8 million quarter-to-quarter primarily due to onshore natural gas pipeline and storage assets Enterprise Products Partners acquired in connection with the GulfTerra merger. These assets accounted for $75.4 million of gross operating margin recorded for this segment during the first quarter of 2005.

 

NGL Pipelines & Services . Gross operating margin from this business segment increased $63.3 million quarter-to-quarter primarily due to improved processing economics and contributions from assets Enterprise Products Partners acquired in connection with the GulfTerra merger and South Texas midstream assets acquisition. Gross operating margin from natural gas processing assets Enterprise Products Partners has acquired since March 31, 2004 accounted for $49.2 million of the increase in gross operating margin for this segment. Gross operating margin from Enterprise Products Partners’ NGL marketing activities and Louisiana natural gas processing facilities increased $14.5 million quarter-to-quarter primarily due to higher NGL prices and restructuring of processing contracts, respectively.

 

Gross operating margin from NGL pipelines and related storage services decreased $3.8 million quarter-to-quarter. Improved gross operating margin from Enterprise Products Partners’ Mid-America and Seminole pipelines and additional gross operating margin amounts attributable to Enterprise Products Partners’ acquisition of additional equity interests in Dixie and Tri-States were more than offset by lower returns from its NGL export facility, south Louisiana pipelines and related assets. Gross operating margin from NGL fractionation increased $9.4 million quarter-to-quarter primarily due to NGL fractionation assets Enterprise Products Partners acquired in connection with the GulfTerra merger. Expenses related to support services classified within this segment increased $5.5 million quarter-to-quarter primarily due to increased business activities related to acquired assets.

 

One of Enterprise Products Partners’ objectives for 2005 was to seek relief through filings with the FERC to increase tariffs on its Mid-America and Seminole pipeline systems to recover increased costs of operating the pipelines, principally those costs attributable to fuel and pipeline integrity expenses. On March 1, 2005, the joint tariff rate for Mid-America and Seminole increased, which should result in additional revenues of approximately $10 million per year on a combined basis for these assets. In addition, the FERC allowed an increase in Mid-America’s local tariffs that became effective May 1, 2005, subject to refund and further review. This increase is expected to provide Enterprise Products Partners’ Mid-America pipeline additional revenues of approximately $12 million per year.

 

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Petrochemical Services . Gross operating margin from this business segment decreased $4.7 million quarter-to-quarter. An increase in gross operating margin from Enterprise Products Partners’ isomerization and propylene fractionation businesses was more than offset by an $8.5 million operating loss at its octane enhancement facility primarily due lower volumes and start-up expenses related to modifications to the facility to add the capability of producing isooctane. As a result of this construction work, the facility was idle during the first quarter. First production of isooctane from the facility was in May 2005.

 

Other . Gross operating margin from this segment pertains to equity earnings Enterprise Products Partners recorded from GulfTerra’s general partner prior to its consolidation with Enterprise Products Partners’ financial results upon completion of the GulfTerra merger on September 30, 2004.

 

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

 

In general, higher energy commodity prices result in increased revenues from Enterprise Products Partners’ NGL and petrochemical marketing activities; however, these same higher prices also increase Enterprise Products Partners’ cost of sales within these activities as feedstock and other related purchase prices rise. For selected general energy commodity price information and detailed segment-level volumetric information, please review the tables under “—Selected Price and Volumetric Information.” The weighted-average market price for NGLs was 73 cents per gallon during 2004 versus 57 cents per gallon during 2003—a year-to-year increase of 28%. Our determination of the weighted-average market price for NGLs is based on selected U.S. Gulf Coast prices for such products at Mont Belvieu, which is the primary industry hub for domestic NGL production. The market price of natural gas (as measured at Henry Hub) averaged $6.13 per MMBtu during 2004 versus $5.38 per MMBtu during 2003. Polymer grade propylene index prices increased 43% year-to-year and refinery grade propylene index prices increased 61% year-to-year.

 

Enterprise Products Partners’ consolidated revenues for 2004 increased $3.0 billion over those recorded during 2003. In general, the trend in consolidated revenues can be attributed to (i) a $2.1 billion increase in revenues from NGL and petrochemical marketing activities primarily resulting from an increase in overall sales volumes and energy commodity market prices; (ii) the addition of $0.6 billion in revenues from businesses acquired during 2004 (primarily GulfTerra and the South Texas midstream assets); and (iii) the addition of $0.2 billion in revenues from businesses acquired during interim periods in 2003 for which a full year’s results are present during 2004 (e.g., BEF).

 

Consolidated costs and expenses increased $2.9 billion period-to-period primarily due to (i) an increase in volumes purchased including the effects of higher energy commodity market prices, which resulted in a $2.0 billion increase in the cost of sales related to our NGL and petrochemical marketing activities and (ii) the addition of $0.5 billion of costs and expenses attributable to businesses acquired or consolidated during 2004. These increases in costs and expenses were partially offset by a gain on sale of assets of approximately $15.1 million related to the satisfaction of certain contractual requirements of a joint venture participation agreement whereby a 50% interest in Cameron Highway was sold. Approximately $10.1 million of this gain was the non-cash recognition of a long-term receivable that is due no later than December 31, 2006 while $5.0 million of the gain was associated with a contractually required cash payment received during the fourth quarter of 2004.

 

Enterprise Products Partners’ equity in earnings of unconsolidated affiliates increased $66.7 million period-to-period. The equity earnings Enterprise Products Partners recorded for 2003 were impacted by a $22.5 million non-cash asset impairment charge associated with its octane enhancement business, BEF. The 2004 period includes $32 million of equity earnings from GulfTerra’s general partner, which Enterprise Products Partners began consolidating on September 30, 2004, as a result of completing the GulfTerra merger. Additionally, 2004 includes equity earnings from investments acquired by Enterprise Products Partners in connection with the GulfTerra merger.

 

As a result of items noted in the previous paragraphs, operating income for 2004 increased $174.9 million from that recorded during 2003. Total segment gross operating margin increased $244.8 million year-to-year due

 

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to the same general reasons underlying the increase in operating income—see the detailed discussion of gross operating margin by business segment below. In addition, see Note 18, Segment Information, in the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP for supplemental financial information for each of the business segment operations. Operating income includes costs such as depreciation and amortization and selling, general and administrative expenses that are excluded from the non-GAAP financial measure of total segment gross operating margin.

 

Net income increased $163.8 million to $268.3 million for 2004 compared to $104.5 million for 2003. Net income for 2004 included a $14.9 million increase in interest expense due to acquisition-related borrowings offset by a $10.8 million benefit associated with the cumulative effect of changes in accounting principles adopted during 2004. For additional information regarding the cumulative effect of changes in accounting principles Enterprise Products Partners recorded during 2004, please read “—Other Items.”

 

The following information highlights the significant year-to-year variances in gross operating margin by business segment; selling, general and administrative costs; and interest expense:

 

Onshore Natural Gas Pipelines & Services . Gross operating margin for Enterprise Products Partners’ Onshore Natural Gas Pipelines & Services segment was $91 million for 2004 compared to $18.3 million for 2003. The majority of the $72.7 million increase in gross operating margin for this segment is attributable to assets acquired in the GulfTerra merger, including various onshore natural gas pipelines and the Petal and Hattiesburg natural gas storage facilities. Additionally, gross operating margin for its Acadian gas pipeline system increased $6.8 million period-to-period due to higher natural gas transportation volumes and natural gas sales margins during 2004. The natural gas throughput volumes on its Acadian system were 595 billion British thermal units per day, or BBtus/d, for 2004 compared to 550 BBtus/d for 2003.

 

NGL Pipelines & Services . Gross operating margin from Enterprise Products Partners’ NGL Pipelines & Services segment was $374.2 million for 2004 compared to $310.7 million for 2003. Gross operating margin for natural gas processing increased $81.4 million period-to-period due to improved processing economics in 2004; the addition of gross operating margin attributable to assets acquired in the GulfTerra merger, including the Chaco, Indian Basin and South Texas natural gas processing facilities; both partially offset by lower results from its NGL marketing activities in 2004. Indicative gas processing gross spreads on the U.S. Gulf Coast averaged 18 cents per gallon during 2004 compared to 9 cents per gallon in 2003, which resulted in an increase in the amount of NGLs extracted. Equity NGL production was 129 MBbls/d for 2004 versus 43 MBbls/d in 2003. Natural gas processing volumes under contracts with fee-based components increased to 1,692 MMcf/d for 2004 from 194 MMcf/d in 2003 reflecting amendments to its natural gas processing contract mix.

 

Gross operating margin from NGL pipelines and storage services decreased $24.7 million period-to-period due to (i) a $4 million non-cash asset impairment charge Enterprise Products Partners recognized in 2004 on an NGL storage facility; (ii) increased expenses associated with its pipeline integrity inspection program; and (iii) lower gross operating margin from its Lou-Tex NGL pipeline resulting from a 17 MBbls/d decrease in volumes due to its election to maximize total gross operating margin by diverting mixed NGLs and refinery-grade propylene to its other facilities. Partially offsetting these decreases was improved gross operating margin from its Mid-America and Seminole pipelines resulting from a 10% increase in throughput volumes. Overall, net NGL transportation volumes were 1,411 MBbls/d for 2004 compared to 1,275 MBbls/d in 2003.

 

Gross operating margin from NGL fractionation increased $6.8 million period-to-period. NGL fractionation volumes were 307 MBbls/d in 2004 compared to 227 MBbls/d in 2003. Gross operating margin from its Norco facility increased by $16.5 million primarily due to (i) a 16 MBbls/d increase in volumes resulting from an expansion completed in the fourth quarter of 2003 and (ii) the effect of higher prices on and an increase in NGL volumes sold by Norco that it earns ownership of through percent-of-liquids based fractionation contracts. Additionally, an increase in gross operating margin of $5.8 million is attributable to the South Texas fractionators which Enterprise Products Partners acquired in the GulfTerra merger. These increases were partially offset by a

 

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$14 million decrease in gross operating margin period-to-period from its Mont Belvieu NGL fractionator primarily attributable to the timing of gains and losses associated with the measurement of NGLs in storage pending fractionation and increased operating costs due to higher natural gas prices.

 

Petrochemical Services . Gross operating margin from its Petrochemical Services segment was $121.5 million in 2004 compared to $75.9 million in 2003. Gross operating margin from octane enhancement increased $34.4 million period-to-period primarily due to (i) a non-cash asset impairment charge of $22.5 million recorded in 2003 related to its investment in BEF and (ii) consolidating the results of BEF after its acquisition of the remaining 33.3% ownership interest during the third quarter of 2004. Gross operating margin from propylene fractionation increased $10.1 million period-to-period primarily due to higher petrochemical marketing sales volumes, which benefited from the effects of higher polymer grade propylene prices in 2004.

 

Offshore Pipelines & Services . Gross operating margin for its Offshore Pipelines & Services segment was $36.5 million for 2004 compared to $5.6 million for 2003. The $30.9 million increase in this segment is primarily attributable to assets acquired in the GulfTerra merger, including various offshore oil and natural gas pipelines and offshore platforms. Partially offsetting this increase in gross operating margin is decreased equity earnings from its Neptune natural gas pipeline investment resulting from a decrease in volumes from the Brutus and Hickory fields and natural depletion of other production fields served by this system.

 

General and administrative costs . General and administrative costs were $46.7 million for 2004 compared to $37.6 million during 2003. The $9.1 million increase is primarily attributable to assets acquired or consolidated during 2004.

 

Interest expense . Interest expense increased to $155.7 million during 2004 from $140.8 million in 2003. The $14.9 million increase is primarily due to additional debt Enterprise Products Partners incurred as a result of the GulfTerra merger, partially offset by reduced loan cost amortization primarily related to its repayment during 2003 of the $1.2 billion senior unsecured 364-day term loan which Enterprise Products Partners used to fund the acquisition of its interests in the Mid-America and Seminole pipelines. Enterprise Products Partners weighted-average debt principal outstanding was $2.8 billion during 2004 compared to $2.0 billion during 2003. For additional information regarding its debt obligations and changes in its debt obligations since December 31, 2003, please read “—Debt Obligations.”

 

Comparison of Year Ended December 31, 2003 with Year Ended December 31, 2002

 

The weighted-average market price for NGLs was 57 cents per gallon during 2003 versus 41 cents per gallon during 2002—a 39% increase year-to-year. The Henry Hub market price of natural gas averaged $5.38 per MMBtu during 2003 versus $3.22 per MMBtu during 2002. Polymer grade propylene index prices increased 15% year-to-year and refinery grade propylene index prices increased 20% year-to-year.

 

Consolidated revenues for 2003 increased $1.8 billion over those recorded during 2002. The majority of the trend in consolidated revenues can be attributed to (i) a $1.4 billion increase in revenues from NGL and petrochemical marketing activities primarily resulting from an increase in energy commodity market prices and (ii) the addition of $0.2 billion in revenues from businesses acquired during interim periods in 2002 for which a full year’s results are present during 2003 (e.g., Mid-America and Seminole pipelines).

 

Consolidated costs and expenses increased $1.7 billion period-to-period primarily due to (i) an increase in volumes purchased including the effects of higher energy commodity market prices which resulted in a $1.3 billion increase in the cost of sales related to Enterprise Products Partners’ NGL and petrochemical marketing activities and (ii) the addition of $0.1 billion in costs and expenses attributable to businesses acquired during 2002 for which a full year’s results are present during 2003. In addition, costs and expenses for 2002 includes a $51.3 million loss related to commodity hedging activities. Also, the increase in natural gas market prices during 2003 resulted in higher energy-related operating costs for many of its businesses versus the same period in 2002.

 

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In addition to the changes in consolidated revenues and costs and expenses mentioned above, when compared to 2002, volumes at some of Enterprise Products Partners’ downstream pipelines and facilities were lower due to a combination of (i) decreased demand for NGLs, principally ethane, by the ethylene segment of the petrochemical industry, which we refer to as the ethylene industry and (ii) lower NGL extraction rates at domestic gas processing facilities. The most significant determinant of the relative economic value of NGLs is demand by the ethylene industry for use in manufacturing plastics and chemicals. During 2003, this industry operated at lower utilization rates when compared to 2002 primarily due to a recession in the domestic manufacturing sector. Also during 2003, as a result of the higher relative cost of NGLs to crude-based alternatives such as naphtha, the ethylene industry utilized crude-based feedstock alternatives in greater quantities than during 2002. The resulting weaker demand for NGLs by this industry limited the ability of NGL producers to sell at higher product prices, which in turn resulted in decreased NGL extraction rates during 2003.

 

Equity earnings from unconsolidated affiliates decreased $49.2 million year-to-year primarily due to a $36.4 million decrease in equity earnings from BEF. The $36.4 million decrease in equity earnings from BEF is primarily due to a $22.5 million asset impairment charge we recorded during the third quarter of 2003; increased facility downtime during 2003 for maintenance and economic reasons; and an overall decrease in MTBE sales margins. In addition to lower earnings from BEF, approximately $4.8 million of the overall decrease in equity earnings is due to a rate case settlement recorded by Starfish in 2002.

 

As a result of items noted in the previous paragraphs, operating income for 2003 increased $53.8 million from that posted during 2002. Total segment gross operating margin increased $78.1 million year-to-year due to the same general reasons underlying the increase in operating income—see the detailed discussion of gross operating margin by business segment below. Operating income includes costs such as depreciation and amortization and selling, general and administrative expenses that are excluded from the non-GAAP financial measure of total segment gross operating margin.

 

Net income increased $9 million to $104.5 million for 2003 compared to $95.5 million for 2002. Net income for 2003 reflected the $53.8 million increase in operating income discussed in the previous paragraph offset by a $39.2 million increase in interest expense due to acquisition-related borrowings.

 

The following information highlights the significant year-to-year variances in gross operating margin by business segment; selling, general and administrative costs; and interest expense:

 

Onshore Natural Gas Pipelines & Services . Gross operating margin from Enterprise Products Partners’ Onshore Natural Gas Pipelines & Services segment was $18.3 million for 2003 compared to $22.1 million for 2002. The decrease in gross operating margin was primarily due to lower natural gas sales volumes attributable to an increase in natural gas prices period-to-period. Overall, natural gas throughput volumes were 600 BBtus/d during 2003 versus 701 BBtus/d during 2002. The market price of natural gas averaged $5.38 per MMBtu during 2003 versus $3.22 per MMBtu during 2002.

 

NGL Pipelines & Services . Gross operating margin from Enterprise Products Partners’ NGL Pipelines & Services segment was $310.7 million for 2003 versus $181.9 million for 2002. Gross operating margin from natural gas processing increased $49.3 million period-to-period. Enterprise Products Partners’ results for 2002 include $51.3 million in commodity hedging losses, the underlying strategies of which were discontinued in 2002. Enterprise Products Partners’ commodity hedging results for 2003 were a gain of $0.2 million.

 

Equity NGL production at Enterprise Products Partners’ gas processing plants averaged 43 MBbls/d during 2003 compared to 73 MBbls/d during 2002. The decrease in equity NGL production year-to-year was largely attributable to reduced demand for NGLs, principally ethane, by the ethylene industry and higher natural gas prices relative to NGL prices, which caused most natural gas processors to minimize the amount of NGLs extracted at their facilities.

 

During 2003, Enterprise Products Partners renegotiated a number of its natural gas processing contracts. In general, its objective has been to convert its traditional keepwhole arrangements to either margin-band/

 

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keepwhole contracts, percent-of-liquids contracts or fee-based contracts. The goal of these renegotiations was to minimize its direct exposure to the volatility of natural gas prices, especially to the extent it increases the plant thermal reduction, or PTR, cost Enterprise Products Partners would pay under traditional keepwhole arrangements to the point that processing natural gas to extract NGLs becomes uneconomical for Enterprise Products Partners. When NGL extraction is uneconomical, NGLs are left in the natural gas stream to the extent allowed while keeping the natural gas in compliance with pipeline quality specifications; thus reducing the amount of NGLs available for downstream activities such as pipeline transportation and NGL fractionation.

 

Gross operating margin from NGL pipelines and storage increased $66.5 million period-to-period. The increase in gross operating margin was primarily due to its acquisition of Mid-America Pipeline Company, LLC, or Mid-America, and Seminole Pipeline Company, or Seminole. These two systems earned gross operating margin of $156.3 million during 2003 on aggregate net volumes of 774 MBbls/d. The 2002 period includes $81.1 million in gross operating margin for the five months during 2002 that Enterprise Products Partners owned interests in these systems (August through December). When compared to their historical operating rates, net pipeline transportation volumes on the Mid-America and Seminole systems recorded for 2003 were lower than those reported by these systems for the full year of 2002 primarily due to decreased demand for NGLs, principally ethane, by the ethylene industry and lower NGL extraction rates at regional gas processing facilities. Excluding the contributions of Mid-America and Seminole, gross operating margin from NGL pipelines and storage was $77.3 million for 2003 versus $86 million for 2002. Net pipeline throughput volumes (excluding Mid-America and Seminole) increased to 501 MBbls/d during 2003 from 463 MBbls/d during the 2002 period.

 

Gross operating margin from NGL fractionation improved $12.9 million year-to-year. The increase in NGL fractionation gross operating margin is primarily due to (i) mixed NGL measurement gains Enterprise Products Partners recognized during 2003 at its Mont Belvieu facility and (ii) higher percent-of-liquids revenues during 2003 at Norco attributable to the general increase in NGL prices, both of which more than offset a decline in gross operating margin from its other NGL fractionation facilities generally due to lower volumes and higher energy-related costs. Net NGL fractionation volumes decreased to 227 MBbls/d during 2003 from 235 MBbls/d during 2002. The decrease in NGL fractionation volumes period-to-period was primarily due to lower NGL extraction rates at gas processing facilities and reduced demand for NGLs by the petrochemical industry.

 

Petrochemical Services . Gross operating margin from Enterprise Products Partners’ Petrochemical Services segment was $75.9 million for the 2003 period compared to $117.8 for the 2002 period. Gross operating margin from propylene fractionation declined $7.4 million year-to-year primarily due to lower petrochemical marketing margins resulting from higher feedstock and energy-related operating costs. Net propylene fractionation volumes were 57 MBbls/d for 2003 compared to 55 MBbls/d during 2002.

 

Gross operating margin from butane isomerization increased $6.8 million year-to-year. The increase in gross operating margin from isomerization was generally attributable to higher isomerization fees and by-product revenues, which were partially offset by lower volumes and higher energy-related operating costs. Isomerization volumes were 77 MBbls/d during the 2003 period compared to 84 MBbls/d during the 2002 period.

 

Enterprise Products Partners’ equity and consolidated earnings from octane enhancement were a loss of $32.7 million for 2003 compared to equity income of $8.6 million during 2002. The $41.3 million decrease in equity earnings is primarily due to a $22.5 million impairment charge Enterprise Products Partners recorded during the third quarter of 2003 for its share of an impairment charge recorded by BEF; increased downtime during 2003 for maintenance and economic reasons; and an overall decrease in MTBE sales margins. Net MTBE production from this facility decreased to 4 MBbls/d during 2003 from 5 MBbls/d during 2002.

 

Offshore Pipelines & Services . Gross operating margin from Enterprise Products Partners’ Offshore Pipelines & Services segment was $5.6 million for 2003 compared to $10.5 million for 2002. Overall, natural gas throughput volumes were 433 BBtus/d during 2003 versus 500 BBtus/d during 2002. The decrease in gross operating margin is primarily due to a $4.8 million reduction in equity earnings from Starfish related to the settlement of a rate case in 2002.

 

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General and administrative costs . These expenses were $37.6 million for 2003 compared to $42.9 million during 2002. The 2002 period includes approximately $10.0 million that Enterprise Products Partners paid to Williams for transition services associated with its acquisition of Mid-America and Seminole compared to $2.0 million paid in 2003 for these services. These payments ceased in February 2003 when Enterprise Products Partners began operating these two pipeline systems.

 

Interest expense . Interest expense increased to $140.8 million during 2003 from $101.6 million in 2002. The increase is primarily due to additional debt Enterprise Products Partners incurred as a result of business acquisitions. Interest expense for 2003 includes $11.3 million of loan cost amortization related to the 364-Day Term Loan, which was incurred in July 2002 and fully repaid in February 2003. Enterprise Products Partners’ weighted-average debt principal outstanding was $2.0 billion during 2003 compared to $1.8 billion during 2002.

 

General Outlook for 2005

 

Enterprise Products Partners expects its business to be affected by the following key trends and events during 2005. Enterprise Products Partners’ expectations are based on assumptions made by it and information currently available to it. To the extent its underlying assumptions about or interpretations of available information prove to be incorrect, Enterprise Products Partners’ actual results may vary materially from its expectations.

 

    Drilling activity in the major producing areas, including the deepwater Gulf of Mexico, Rocky Mountains and San Juan, and the improving economy have increased demand for Enterprise Products Partners’ integrated midstream energy services. Over the next two years Enterprise Products Partners expects large volumes of new production from both the deepwater and the Rockies to flow into its integrated system of assets.

 

    Enterprise Products Partners’ natural gas and NGL facilities in central Louisiana and its 50% owned Cameron Highway oil pipeline began receiving first production in January 2005 from the Mad Dog and Holstein developments in the Southern Green Canyon area of the deepwater Gulf of Mexico. These volumes, along with oil volumes received by its 36% owned Poseidon oil pipeline from the Front Runner development, should steadily increase during 2005 as these developments ramp up to full production. In addition, Enterprise Products Partners expects initial production from the K-2 and K-2 North fields to begin flowing into its facilities in mid-2005.

 

    As a result of the continued strong demand for NGLs, most of Enterprise Products Partners’ pipelines, fractionators and processing plants should continue to run at high utilization rates. The strength of the domestic and global economic recoveries should continue to drive increased demand for all forms of energy despite higher commodity prices. Enterprise Products Partners’ largest NGL consuming customers in the ethylene industry have seen strong demand for their products, which has enabled them to raise prices to mitigate higher fuel and feedstock costs. With the unusually high price of crude oil relative to natural gas, ethane and propane are the preferred feedstocks of the ethylene industry. With strong demand for their products, the ethylene industry has been operating at utilization rates in excess of 90%, which results in strong demand for all ethylene feedstocks.

 

    As a result of the GulfTerra merger, Enterprise Products Partners significantly increased its midstream assets located in the Gulf of Mexico. Enterprise Products Partners has several projects that have either recently started operations or are scheduled to become operational soon. For additional information regarding these projects and its other capital spending, please read “—Capital Spending.”

 

    The effects of Hurricane Ivan have reduced volumes delivered to some of Enterprise Products Partners’ pipelines, natural gas processing and NGL fractionation facilities in eastern Louisiana since the middle of September 2004. Enterprise Products Partners estimates that this reduction in volumes resulted in a $24 million decrease in gross operating margin for the year ended December 31, 2004. This amount is prior to any potential recoveries under its business interruption insurance. In December 2004, volumes to these pipelines and facilities started to increase, and Enterprise Products Partners expects the volumes to return to normal levels by mid-2005.

 

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Liquidity and Capital Resources

 

Enterprise GP Holdings

 

Our primary cash requirements are for distributions to partners, capital contributions to maintain Enterprise Products GP’s 2% general partner interest in Enterprise Products Partners, debt service requirements and general, administrative and other expenses. We expect to fund distributions to partners, debt service requirements and general, administrative and other expenses primarily with the quarterly cash distributions we receive from Enterprise Products Partners, and we expect to fund capital contributions through borrowings under our new credit facility, which we will enter into concurrently with the closing of this offering. Any other liquidity and capital resource requirements may also be met initially through borrowings under our new credit facility. Please read “—Debt Obligations—Enterprise GP Holdings.”

 

Concurrently with the closing of this offering, we will enter into a new $525 million credit facility consisting of a $475 million term loan and a $50 million revolving credit facility. We intend to use $25 million of the net proceeds of this offering to repay a portion of the outstanding revolving borrowings and the remaining net proceeds of approximately $280 million to repay a portion of the outstanding term borrowings, thus initially providing us with $25 million of liquidity under the revolving portion of our new credit facility for general partnership purposes, including capital contributions to Enterprise Products Partners. On a pro forma as adjusted basis giving effect to the application of proceeds from this offering, we expect this facility to have outstanding borrowings of approximately $220 million bearing interest at 6.0% per annum. This facility will have a maturity date in February 2006; however, we intend to refinance this indebtedness with a new multi-year credit facility prior to this maturity date. Please read “—Debt Obligations—Enterprise GP Holdings.”

 

Because we depend on cash distributions from Enterprise Products Partners to meet our liquidity and capital resource requirements, the following information regarding Enterprise Products Partners’ liquidity and capital resource requirements has been provided to assist you in understanding how Enterprise Products Partners’ cash flows are derived.

 

Enterprise Products Partners

 

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

 

As noted above, certain of Enterprise Products Partners’ liquidity and capital resource requirements are fulfilled by borrowings made under debt agreements and/or proceeds from the issuance of additional partnership equity. At March 31, 2005, Enterprise Products Partners had $58 million of unrestricted cash and approximately $430 million of credit under its multi-year revolving credit facility. At March 31, 2005, Enterprise Products Partners had approximately $4.2 billion in principal outstanding under various debt agreements. For additional information regarding its debt, please read “—Debt Obligations.”

 

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

 

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Registration Statements

 

In February 2001, Enterprise Products Partners filed a universal shelf registration statement with the Commission covering the issuance of up to $500 million of partnership equity or public debt obligations. In October 2002, Enterprise Products Partners sold 9,800,000 common units under this shelf registration statement from which it received net proceeds of $182.5 million, including Enterprise Products GP’s proportionate net capital contribution of $3.7 million. In January 2003, Enterprise Products Partners sold an additional 14,662,500 common units under this shelf registration statement from which it received net proceeds of $258.1 million, including Enterprise Products GP’s proportionate net capital contribution of $5.2 million. Enterprise Products Partners used the net proceeds from these equity offerings to reduce debt outstanding under the Operating Partnership’s 364-Day Term Loan and for working capital purposes. After deducting for these issuances of common units in October 2002 and January 2003, practically all of the available capacity under this shelf registration statement was used.

 

In January 2003, Enterprise Products Partners filed a $1.5 billion universal shelf registration statement with the Commission covering the issuance of an unallocated amount of partnership equity or public debt obligations (separately or in combination). Enterprise Products Partners sold 65,660,317 common units under this registration statement.

 

    In June 2003, Enterprise Products Partners sold 11,960,000 common units under this shelf registration statement from which it received net proceeds of $261.1 million, including Enterprise Products GP’s proportionate net capital contribution of $5.2 million. Enterprise Products Partners used the net proceeds from this offering to reduce indebtedness outstanding under the Operating Partnership’s revolving credit facilities.

 

    In May 2004, Enterprise Products Partners sold 17,250,000 common units under this registration statement from which it received net proceeds of $353.1 million, including Enterprise Products GP’s proportionate net capital contribution of $7.1 million. Enterprise Products Partners used the proceeds from this public offering to repay the Operating Partnership’s $225 million Interim Term Loan and to temporarily reduce borrowings outstanding under the Operating Partnership’s revolving credit facilities.

 

    In August 2004, Enterprise Products Partners sold 17,250,000 common units under this registration statement from which it received net proceeds of $341.2 million, including Enterprise Products GP’s proportionate net capital contribution of $6.8 million. Enterprise Products Partners used $210 million of the proceeds from this public offering to reduce borrowings outstanding under its revolving credit facilities and the remainder to fund its payment obligations to El Paso under step two of the GulfTerra merger.

 

    In October and November 2004, Enterprise Products Partners sold 1,950,317 common units under this registration statement from which it received net proceeds of $39.6 million, including Enterprise Products GP’s proportionate net capital contributions. These common units were issued as a result of the conversion of GulfTerra’s 80 outstanding Series F2 convertible units, which Enterprise Products Partners assumed as a result of the merger, into Enterprise common units.

 

    In February 2005, Enterprise Products Partners sold 17,250,000 common units under this registration statement (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005) from which it received net proceeds of approximately $456.5 million, including Enterprise Products GP’s proportionate net capital contribution of $9.1 million. Enterprise Products Partners used the proceeds from this public offering to repay the Operating Partnership’s 364-day acquisition credit facility, to temporarily reduce indebtedness outstanding under the Operating Partnership’s multi-year revolving credit facility or for general partnership purposes.

 

After deducting for these issuances of common units in 2003, 2004 and 2005, practically all of the available capacity under this shelf registration statement was used.

 

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On March 3, 2005, Enterprise Products Partners filed a universal shelf registration statement with the Commission registering the issuance of $4 billion of partnership equity and public debt obligations, which was declared effective by the Commission on March 23, 2005. In connection with this registration statement, Enterprise Products Partners also registered for resale 36,572,122 common units currently owned by Shell US Gas & Power, LLC, an affiliate of Shell Oil Company, and 4,427,878 common units owned by third party, Kayne Anderson MLP Investment Company. Shell sold these unregistered units to Kayne Anderson in December 2004. On April 1, 2005, Shell sold an additional 1,203,600 common units to Kayne Anderson. Enterprise Products Partners is obligated to register the resale of these common units for Shell under a registration rights agreement it executed with Shell in connection with its acquisition of certain of Shell’s Gulf Coast midstream energy businesses in September 1999.

 

In June 2005, the Operating Partnership sold $500 million in principal amount of five-year senior unsecured notes under this registration statement. The notes were issued at 99.834% of their principal amount and have a fixed-rate interest of 4.95% and a maturity date of June 1, 2010. The Operating Partnership used the net proceeds from the issuance of these notes to temporarily reduce borrowings outstanding under its multi-year revolving credit facility and for general partnership purposes, including capital expenditures and acquisitions.

 

In July 2003, Enterprise Products Partners filed a registration statement with the Commission covering 5,000,000 common units issuable under its Distribution Reinvestment Plan, or DRIP. In April 2004, Enterprise Products Partners filed a new registration statement with the Commission covering an additional 10,000,000 common units issuable under the DRIP. The new registration statement increased the number of Enterprise Products Partners’ common units issuable under the DRIP from 5,000,000 to 15,000,000. The DRIP provides Enterprise Products Partners’ unitholders of record and beneficial owners of its common units a voluntary means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional common units. Enterprise Products Partners expects to use the cash generated from this reinvestment program primarily for general partnership purposes. Initial reinvestments under the DRIP occurred in August 2003. For all of 2003, Enterprise Products Partners issued 2,883,803 common units in connection with the DRIP and received proceeds (including Enterprise Products GP’s proportionate net capital contributions) of approximately $60.3 million. During 2004, Enterprise Products Partners issued 5,183,591 common units in connection with the DRIP and received proceeds (including Enterprise Products GP’s proportionate net capital contributions) of approximately $111.6 million. To support its growth objectives and financial flexibility, EPCO reinvested approximately $177.5 million of its cash distributions from August 2003 through February 2005 through the DRIP.

 

Class B special units

 

In December 2003, Enterprise Products Partners sold 4,413,549 Class B special units to an affiliate of EPCO for $100 million in a private transaction. Enterprise Products GP contributed approximately $2 million in connection with this offering in order to maintain its ownership interest. Enterprise Products Partners used the net proceeds from this offering to repay $100 million of the debt it incurred to finance its December 2003 purchase of a 50% interest in GulfTerra’s general partner and the remainder for general partnership purposes. Upon receipt of Enterprise Products Partners unitholder approval on July 29, 2004, its 4,413,549 Class B special units converted to an equal number of common units. This conversion resulted in a reclassification of the $99 million capital account balance for the Class B special units to common units.

 

Series F2 convertible units assumed in connection with the GulfTerra merger

 

In May 2003, GulfTerra issued 80 Series F convertible units in a registered offering to an institutional investor. Each Series F convertible unit was comprised of two separate detachable units—a Series F1 convertible unit and a Series F2 convertible unit—that had identical terms except for vesting and termination dates and the number of common units into which they may be converted. Prior to the GulfTerra merger, all the Series F1 convertible units were converted. As a result of the GulfTerra merger, Enterprise Products Partners assumed

 

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GulfTerra’s obligations associated with the 80 Series F2 convertible units. All Series F2 convertible units outstanding at the merger date were converted into rights to receive Enterprise Products Partners’ common units. The number of Enterprise Products Partners’ common units and the price per unit at conversion were adjusted based on the 1.81 exchange ratio. The Series F2 convertible units were convertible into up to $40 million of Enterprise Products Partners common units.

 

On October 29, 2004, 60 of the 80 outstanding Series F2 convertible units were converted into 1,458,434 Enterprise Products Partners common units. As a result of this conversion, Enterprise Products Partners received a payment of $30 million from the holder of the Series F2 convertible units (representing a conversion price of $20.57 per Enterprise common unit). Net proceeds from this conversion, including Enterprise Products GP’s proportionate capital contribution of $0.6 million, were $29.7 million after deducting transaction costs of $0.9 million.

 

On November 8, 2004, the remaining 20 outstanding Series F2 convertible units were converted into 491,883 Enterprise Products Partners common units. As a result of this conversion, Enterprise Products Partners received a payment of $10 million from the holder of the Series F2 convertible units (representing a conversion price of $20.33 per Enterprise common unit). Net proceeds from this conversion, including Enterprise Products GP’s proportionate capital contribution of $0.2 million, were $9.9 million after deducting transaction costs of $0.3 million.

 

Cash Flows from Operating, Investing and Financing Activities

 

Cash flows from operating activities primarily reflect net income adjusted for depreciation, amortization and similar non-cash amounts; equity earnings and cash distributions from unconsolidated affiliates and changes in operating accounts. For additional information regarding changes in operating accounts, please read the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Cash flow from operations is primarily based on earnings from its business activities. As a result, these cash flows are exposed to certain risks. Enterprise Products Partners operates predominantly in the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. In general, Enterprise Products Partners provides services for producers and consumers of natural gas, NGLs and crude oil from the wellhead to the end user. The products that Enterprise Products Partners processes, sells or transports are principally used as fuel for residential, agricultural and commercial heating, feedstocks in petrochemical manufacturing, and in the production of motor gasoline. Reduced demand for Enterprise Products Partners’ services or products by industrial customers, whether because of general economic conditions, reduced demand for the end products made with its products or increased competition from other service providers or producers due to pricing differences or other reasons could have a negative impact on Enterprise Products Partners’ earnings and thus the availability of cash from operating activities. Other risks include fluctuations in oil, natural gas and NGL prices, competitive practices in the midstream energy industry and the impact of operational and systems risks. For a more complete discussion of these and other risk factors pertinent to Enterprise Products Partners’ business, please read “Risk Factors—Risks Related to Enterprise Products Partners’ Business.”

 

Comparison of Three Months Ended March 31, 2005 with Three Months Ended March 31, 2004

 

Operating activities. For the three months ended March 31, 2005 and 2004, cash provided by operating activities was $180 million and $29.6 million, respectively. The quarter-to-quarter increase of $150.4 million in cash provided by operating activities was primarily attributable to increased earnings as discussed under “—Results of Operations.”

 

The quarter-to-quarter fluctuations of the remaining significant line items, as presented on the Unaudited Condensed Statements of Consolidated Cash Flows, are attributable to (i) a $10 million increase in cash resulting

 

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from a decrease in the restricted cash balance, which is primarily due to the timing of physical purchases of natural gas on the New York Mercantile exchange, or NYMEX and (ii) a $9.5 million increase in cash resulting from the net effects of changes in operating accounts which is generally the result of timing of cash receipts from sales and cash payments for purchases and other expenses near the end of each period. Additionally, fluctuations in inventory are influenced by changes in commodity prices and Enterprise Products Partners’ marketing activities.

 

Investing activities . For the three months ended March 31, 2005 and 2004, Enterprise Products Partners used $365 million and $15.8 million, respectively, for investing activities. During the first quarter of 2005, Enterprise Products Partners used $74.9 million to purchase from El Paso two entities which owned interests in the Indian Springs natural gas gathering and processing assets and $68 million to purchase an additional 46.1% ownership interest in Dixie. Capital expenditures were $175.2 million during the first quarter of 2005 period compared to $15.2 million for the 2004 period. For additional information regarding Enterprise Products Partners’ capital expenditures, please read “—Capital Spending.” Enterprise Products Partners’ investments in and advances to unconsolidated affiliates were $88.6 million during the first quarter of 2005 compared to $0.8 million during the first quarter of 2004. In March 2005, Enterprise Products Partners contributed $72 million to Deepwater Gateway to fund its share of the repayment of Deepwater Gateway’s $144 million term loan. In addition, Enterprise Products Partners’ investing activities cash flows include $42.1 million in proceeds from the sale of its 50% equity interest in Starfish, which was required to gain regulatory approval for the GulfTerra merger.

 

Financing activities . For the three months ended March 31, 2005 and 2004, Enterprise Products Partners’ cash provided by financing activities was $218.1 million and $0.5 million, respectively. During the first quarter of 2005, Enterprise Products Partners had net repayments on its debt obligations of $118.8 million compared to net borrowings of $65 million during the first quarter of 2004. In February 2005, the Operating Partnership issued an aggregate of $500 million in senior notes, the proceeds of which were used to repay $350 million due under Senior Notes A and to temporarily reduce amounts outstanding under its bank credit facilities. Additionally, Enterprise Products Partners’ repaid the remaining $242.2 million that was due under the Operating Partnership’s 364-day acquisition credit facility using proceeds from its February 2005 equity offering.

 

Cash distributions to partners increased $73.4 million quarter-to-quarter primarily due to an increase in the number of units eligible for distributions and an increase in Enterprise Products Partners’ declared quarterly distribution rate. Enterprise Products Partners expects that future cash distributions to partners will increase as a result of its periodic issuance of common units under the DRIP and other equity offerings. Net proceeds from the issuance of common units were $501 million during the first quarter of 2005 compared to $23.1 million during the first quarter of 2004. The first quarter of 2005 amounts include Enterprise Products Partners’ February 2005 equity offering of 17,250,000 (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005), which generated net proceeds of approximately $456.9 million.

 

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

 

Operating activities. Cash provided by operating activities was $379.2 million during 2004 compared to $419.6 million for 2003. This period-to-period increase in earnings is discussed under “—Results of Operations.”

 

The following is a discussion of the period-to-period fluctuations for the remaining significant line items as presented on the Statements of Consolidated Cash Flows. Distributions received from Enterprise Products Partners’ equity method unconsolidated affiliates during 2004 increased $36.1 million over those received in 2003 primarily due to $32.3 million in cash distributions received from GulfTerra’s general partner and $5.1 million from VESCO, offset by the effects of consolidating former equity method investments as a result of acquisitions. As a result of the GulfTerra merger, GulfTerra’s general partner became a wholly owned subsidiary of the Operating Partnership. Additionally, on July 1, 2004, Enterprise Products Partners changed its method of accounting for VESCO from the cost method to the equity method in accordance with EITF 03-16. As a result, the dividends we received from VESCO that were formerly recognized in earnings under the cost method (prior

 

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to our adoption of EITF 03-16) were reclassified as cash receipts on Enterprise Products Partners’ Statements of Consolidated Cash Flows in 2004.

 

The $7.2 million period-to-period increase in the restricted cash balance is primarily due to the timing of physical purchases of natural gas on the NYMEX exchange, and the $214.6 million period-to-period change in the net effects of changes in operating accounts is generally the result of timing of cash receipts from sales and cash payments for purchases and other expenses near the end of each period. Additionally, fluctuations in inventory are influenced by changes in commodity prices and Enterprise Products Partners’ marketing activities.

 

Investing Activities . During 2004, Enterprise Products Partners used $929.1 million in cash for investing activities compared to $657 million in 2003. Enterprise Products Partners used $638.8 million during 2004 to complete the GulfTerra merger, including its purchase of the South Texas midstream assets. Additionally, during 2004, Enterprise Products Partners used $85.9 million to purchase certain assets located near Morgan’s Point, Texas, an additional 16.7% membership interest in Tri-States NGL Pipeline LLC, or Tri-States, a 10% equity interest in Seminole and the remaining 33.3% ownership interest in BEF. During 2003, Enterprise Products Partners used $37.3 million primarily to purchase the Port Neches Pipeline, the remaining 50% ownership interest in EPIK Terminalling L.P. and EPIK Gas Liquids, LLC, collectively, or EPIK, an additional 33.3% interest in BEF, an additional 37.4% interest in Wilprise Pipeline Company, LLC, or Wilprise, and the remaining 50% interest in Olefins Terminal Corporation, or OTC. Capital expenditures were $146.9 million for 2004 versus $145.9 million for 2003. For additional information regarding Enterprise Products Partners’ capital expenditures, please read “—Capital Spending.” Investments in and advances to unconsolidated affiliates were $64.4 million for 2004 compared to $471.9 million for 2003. During 2004, Enterprise Products Partners used $27.5 million to purchase an additional 16.7% interest in Promix and contributed $24 million to Cameron Highway for the construction of the Cameron Highway oil pipeline. The 2003 period included Enterprise Products Partners’ payment of $425 million to El Paso Corporation for a 50% ownership interest in GulfTerra’s general partner and amounts Enterprise Products Partners contributed to its Gulf of Mexico natural gas pipeline investments for their expansion capital projects.

 

Financing Activities . Cash provided by financing activities during 2004 were $544 million compared to $254 million in 2003. During 2004, Enterprise Products Partners had net borrowings under its debt agreements of $125.6 million compared to net repayments of $106.8 million for 2003. On September 30, 2004, the Operating Partnership borrowed approximately $2.8 million under its new 364-day acquisition credit facility and multi-year revolving credit facility to (a) fund $655.3 million in cash payment obligations to El Paso Corporation under Steps Two and Three of the GulfTerra merger transactions, (b) escrow $1.1 billion to finance its tender offers for GulfTerra’s senior and senior subordinated notes and (c) extinguish $962 million outstanding under GulfTerra’s revolving credit facility and secured term loans. Additionally, on October 4, 2004, the Operating Partnership issued $2 billion in senior notes (Senior Notes E, F, G and H). Enterprise Products Partners’ repayments of debt during 2004 reflect the use of proceeds from its May 2004 and August 2004 equity offerings to repay the $225 million interim term loan and to temporarily reduce amounts outstanding under the Operating Partnership’s pre-merger revolving credit facilities and the use of proceeds from the Operating Partnership’s October 2004 issuance of senior notes to reduce debt amounts outstanding under its 364-day acquisition credit facility. Additionally, on October 5, 2005, the Operating Partnership used the $1.1 billion in escrowed funds to complete its cash tender offers for substantially all of GulfTerra’s senior and senior subordinated notes. The 2003 period reflects the Operating Partnership’s issuance of Senior Notes C ($350 million in principal amount) and Senior Notes D ($500 million in principal amount), and a $425 million borrowing under its interim term loan which was used to purchase a 50% interest in GulfTerra’s general partner. Repayments of debt during 2003 reflect the use of proceeds from equity offerings completed in January, June, August and December and the final repayment of $1 billion that was outstanding under the bridge loan financing Enterprise Products Partners used to purchase interest in the Mid-America and Seminole pipelines.

 

Cash distributions to partners increased from $309.9 million during 2003 to $438.8 million during 2004. The increase in cash distributions is primarily due to an increase in both the declared quarterly distributions and

 

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the number of units eligible for distributions. Enterprise Products Partners expects that future cash distributions to partners will increase as a result of its periodic issuance of common units under the DRIP and other equity offerings.

 

Net proceeds from the issuance of common units were $846.1 million for 2004 compared to $573.7 million for 2003. Both amounts include Enterprise Products GP’s net proportionate capital contributions. In May 2004, Enterprise Products Partners sold 17,250,000 common units to the public (including the underwriters’ over-allotment amount of 2,250,000 common units) at an offering price of $21.00 per unit. Net proceeds from this offering, including Enterprise Products GP’s proportionate net capital contribution of $7.1 million, were $353.1 million after deducting applicable underwriting discounts, commissions and offering expenses of $16.3 million. In August 2004, Enterprise Products Partners sold 17,250,000 common units to the public (including the underwriters’ over-allotment amount of 2,250,000 common units) at an offering price of $20.20 per unit. Net proceeds from this offering, including Enterprise Products GP’s proportionate net capital contribution of $6.8 million, were approximately $341.2 million after deducting applicable underwriting discounts, commissions and offering expenses of $13.9 million. The 2004 period also includes $111.6 million in proceeds from the sale of 5,183,591 common units in connection with the DRIP, the proceeds of which were primarily used for general partnership purposes, and $39.6 million in proceeds from the conversion of 80 Series F2 convertible units into 1,950,317 common units. Proceeds from the issuance of common units during 2003 reflect the sale of 14,662,500 and 11,960,000 common units in its January 2003 and June 2003 equity offerings, respectively, and the sale of 2,883,803 common units in connection with the DRIP. Additionally, the 2003 period reflects the sale of 4,413,549 Class B special units to an affiliate of EPCO in December 2003.

 

Comparison of Year Ended December 31, 2003 with Year Ended December 31, 2002

 

Operating activities. Cash provided by operating activities was $419.6 million during 2003 compared to $326.8 million during 2002. The period-to-period increase in earnings is discussed under “—Results of Operations.”

 

The following is a discussion of the period-to-period fluctuations for the remaining significant line items as presented on the Statements of Consolidated Cash Flows. Distributions received from Enterprise Products Partners’ equity method unconsolidated affiliates during 2003 decreased $25.8 million over those received in 2002 primarily due to the consolidation of former equity method investments as a result of Enterprise Products Partners acquiring controlling interests in such entities. The $28.2 million period-to-period increase in cash flows related to the net effects of changes in operating accounts is generally the result of timing of cash receipts from sales and cash payments for purchases and other expenses near the end of each period. Additionally, increases or decreases in inventory are influenced by changes in commodity prices and Enterprise Products Partners’ marketing activities.

 

Investing Cash Flows . During 2003, Enterprise Products Partners used $657.0 million in cash for investing activities compared to $1.7 billion during 2002. Enterprise Products Partners used $37.3 million and $1.6 billion for business acquisitions during 2003 and 2002, respectively. The 2002 period reflects its acquisition of interests in the Mid-America and Seminole pipelines from Williams and propylene fractionation and NGL and petrochemical storage assets from Diamond-Koch. The 2003 period includes only minor acquisitions, specifically the Port Neches pipeline and additional interests in EPIK, BEF, Wilprise and OTC.

 

Investments in and advances to unconsolidated affiliates increased to $471.9 million during 2003 compared to $13.7 million during 2002. The 2003 period includes its payment of $425 million to El Paso Corporation for a 50% ownership interest in GulfTerra’s general partner in December 2003. The remaining $33.2 million year-to-year increase is primarily due to funding its share of the expansion projects of its Gulf of Mexico natural gas pipeline investments and its purchase of an additional interest in Tri-States.

 

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Enterprise Products Partners’ capital expenditures were $145.9 million during 2003 versus $72.1 million during 2002. The $73.8 million increase in capital expenditures is primarily due to expansions of its Norco NGL fractionator and Neptune gas processing facility.

 

Financing cash flows . Cash provided by financing activities during 2003 was $254 million compared to $1.3 billion during 2002. During 2003, Enterprise Products Partners made net payments on its debt obligations of $106.8 million. Enterprise Products Partners’ borrowings during 2003 include the Operating Partnership’s issuance of Senior Notes C ($350 million in principal amount), Senior Notes D ($500 million in principal amount) and the $425 million borrowing under the Interim Term Loan (to purchase a 50% interest in the general partner of GulfTerra). Enterprise Products Partners’ repayments during 2003 include the use of proceeds from equity offerings completed in January, June, August and December. The 2002 period primarily reflects borrowings to fund the Mid-America and Seminole acquisitions and those of Diamond-Koch’s propylene fractionation business.

 

Proceeds from Enterprise Products Partners’ common unit and Class B special unit equity offerings during 2003 totaled $675.7 million, which includes Enterprise Products GP’s related $7.8 million contribution to Enterprise Products Partners. Enterprise Products GP also contributed $5.9 million to the Operating Partnership in connection with these offerings. Distributions to its partners and minority interests increased to $318.0 million during 2003 from $218.2 million during 2002. The $99.8 million increase in distributions to partners is primarily due to increases in both the declared quarterly distributions and the number of units eligible for distributions.

 

Debt Obligations

 

Enterprise GP Holdings

 

Concurrently with the closing of this offering, we will enter into a new $525 million credit facility consisting of a $475 million term loan and a $50 million revolving credit facility, both maturing on February 24, 2006. This new credit facility will initially be used to repay certain of our outstanding debt. Please read “Use of Proceeds.” We intend to use $25 million of the net proceeds of this offering to repay a portion of the outstanding revolving borrowings and the remaining net proceeds of approximately $280 million to repay a portion of the outstanding revolving borrowings, thus initially providing us with $25 million of liquidity under the revolving portion of our new credit facility to use for general partnership purposes, including capital contributions to Enterprise Products Partners. Borrowings under our new credit facility will be secured by (i) a pledge by us of the 13,454,498 common units of Enterprise Products Partners owned by us; and (ii) a pledge by us of our 100% membership interest in Enterprise Products GP.

 

As defined in our new credit facility, variable interest rates charged under this facility generally will bear interest, at our election at the time of each borrowing at (1) the greater of (a) the interest rate per annum publicly announced by Citibank N.A. as its prime rate or (b) the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published by the Federal Reserve Bank of New York plus ½ of 1%, in either case plus an applicable margin of 1%; or (2) LIBOR plus an applicable margin of 2.25%.

 

Our new credit facility will contain various covenants related to our ability, and the ability of certain of our subsidiaries (including Enterprise Products GP), to incur certain indebtedness, grant certain liens, make fundamental structural changes, make distributions following an event of default and enter into certain restrictive agreements. The new credit facility will also require us to satisfy certain financial covenants as of the end of each fiscal quarter.

 

After this offering, we expect to have borrowings of approximately $220 million outstanding under this facility, with $25 million available under the revolving portion of our credit facility. We intend to refinance the outstanding indebtedness under this new credit facility prior to its maturity with a new multi-year credit facility.

 

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Enterprise Products Partners

 

Enterprise Products Partners’ debt consisted of the following at the dates indicated:

 

     March 31,     December 31,  
     2005

    2004

 
    

(In thousands)

 

Operating Partnership debt obligations:

                

364-Day Acquisition Credit Facility, variable rate, repaid in February 2005(1) (2)

           $ 242,229  

Multi-Year Revolving Credit Facility, variable rate, due September 2009(2)

   $ 300,000       321,000  

Seminole Notes, 6.67% fixed-rate, $15 million due in December 2005(3)

     15,000       15,000  

Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010

     54,000       54,000  

Senior Notes A, 8.25% fixed-rate, repaid March 2005

             350,000  

Senior Notes B, 7.50% fixed-rate, due February 2011

     450,000       450,000  

Senior Notes C, 6.375% fixed-rate, due February 2013

     350,000       350,000  

Senior Notes D, 6.875% fixed-rate, due March 2033

     500,000       500,000  

Senior Notes E, 4.00% fixed-rate, due October 2007

     500,000       500,000  

Senior Notes F, 4.625% fixed-rate, due October 2009

     500,000       500,000  

Senior Notes G, 5.60% fixed-rate, due October 2014

     650,000       650,000  

Senior Notes H, 6.65% fixed-rate, due October 2034

     350,000       350,000  

Senior Notes I, 5.00% fixed-rate, due March 2015

     250,000          

Senior Notes J, 5.75% fixed-rate, due March 2035

     250,000          

Dixie short-term commercial paper debt obligations

     14,000          

GulfTerra debt obligations(3):

                

Senior Notes, 6.25% fixed-rate, due June 2010(4)

             750  

Senior Subordinated Notes, 8.50% fixed-rate, due June 2010

     3,858       3,858  

Senior Subordinated Notes, 8.50% fixed-rate, due June 2011

     1,777       1,777  

Senior Subordinated Notes, 10.625% fixed-rate, due December 2012

     84       84  
    


 


Total principal amount

     4,188,719       4,288,698  

Net unamortized discounts

     (13,940 )     (9,239 )

Other

     (17,476 )     1,777  
    


 


Subtotal long-term debt

     4,157,303       4,281,236  

Less current maturities of debt(5)

     (29,000 )     (15,000 )
    


 


Long-term debt

   $ 4,128,303     $ 4,266,236  
    


 


Standby letters of credit outstanding(6)

   $ 135,152     $ 139,052  

(1) Enterprise Products Partners used the proceeds from its February 2005 common unit offering to fully repay and terminate the 364-Day Acquisition Credit Facility.
(2) These facilities became effective concurrently with the closing of the GulfTerra merger on September 30, 2004. The new $750 million multi-year revolving credit facility replaced the $230 million 364-day revolving credit facility and the $270 million then existing multi-year revolving credit facility. The $750 million borrowing capacity, which is reduced by the amount of standby letters of credit outstanding.
(3) Solely as it relates to the assets of its GulfTerra and Seminole subsidiaries, its senior indebtedness is structurally subordinated and ranks junior in right of payment to indebtedness of GulfTerra and Seminole.
(4) Remaining notes outstanding were called and retired in February 2005.
(5) In accordance with SFAS No. 6, “Classification of Short-Term Obligations Expected to Be Refinanced,” long-term and current maturities of debt at December 31, 2004 reflected (i) its refinancing of Senior Notes A with proceeds from its Senior Notes I and J in March 2005 and (ii) the repayment of its 364-day acquisition credit facility using proceeds from an equity offering completed in February 2005.
(6) Of the $135 million and $139 million standby letters of credit outstanding at March 31, 2005 and December 31, 2004, $115 million is associated with a letter of credit facility Enterprise Products Partners entered into in November 2004 in connection with its Independence Hub capital project, and the remaining amounts were issued under its Multi-Year Revolving Credit Facility.

 

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General description of consolidated debt

 

The following is a summary of the significant aspects of Enterprise Products Partners’ debt obligations at March 31, 2005:

 

Parent-Subsidiary Guarantor Relationships . Enterprise Products Partners acts as guarantor of the debt obligations of the Operating Partnership, with the exception of the Seminole Notes, Dixie commercial paper obligations and the senior subordinated notes of GulfTerra. If the Operating Partnership were to default on any debt Enterprise Products Partners guarantees, Enterprise Products Partners would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which Enterprise Products Partners owns an effective 88.4% of its capital stock). The senior and senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra, of which Enterprise Products Partners owns 100% of the limited and general partnership interests.

 

GulfTerra’s Senior and Senior Subordinated Notes . As a result of completing the GulfTerra merger on September 30, 2004, Enterprise Products Partners recorded in consolidation GulfTerra’s $921.5 million of outstanding senior and senior subordinated notes. Of this amount, $915 million was purchased on October 5, 2004 by the Operating Partnership pursuant to its tender offers. The note holders also approved amendments in connection with accepting the tender offers that removed all restrictive covenants governing the notes. For additional information regarding the tender offers, please read “—Tender Offers for GulfTerra Senior and Senior Subordinated Notes” within this general description of debt. In February 2005, Enterprise Products Partners redeemed, at a premium, the remaining $0.8 million outstanding under GulfTerra’s 6.25% senior notes due June 2010.

 

364-Day Acquisition Credit Facility . In August 2004, the Operating Partnership entered into a new 364-day acquisition credit facility. The $2.25 billion acquisition credit facility was an unsecured 364-day facility that was used to provide interim financing for certain transactions associated with the GulfTerra merger, the refinancing of GulfTerra’s existing secured credit facility and term loans and the purchase of GulfTerra’s senior and senior subordinated notes in connection with the Operating Partnership’s tender offers for those notes. This facility became effective concurrent with the closing of the GulfTerra merger and was to mature on September 29, 2005. In February 2005, Enterprise Products Partners fully repaid and terminated the 364-day acquisition credit facility using proceeds it received from its February 2005 common unit offering. For additional information regarding the February 2005 common unit offering, please read “—Recent Developments.”

 

Tender Offers for GulfTerra Senior and Senior Subordinated Notes. On August 4, 2004, in anticipation of completing the GulfTerra merger, the Operating Partnership commenced four cash tender offers to purchase any and all of the outstanding senior and senior subordinated notes of GulfTerra having a total outstanding principal amount of approximately $921.5 million. In connection with the tender offers, GulfTerra executed supplements to the indentures governing these notes that eliminated certain restrictive covenants and default provisions contained in those indentures upon its purchase of more than a majority in principal amount of each series of the outstanding senior and senior subordinated notes.

 

Substantially all of the GulfTerra notes ($915 million of $921.5 million) were tendered pursuant to the tender offers. On September 30, 2004, the Operating Partnership borrowed $1.1 billion under its 364-day acquisition credit facility in anticipation of completing the tender offers and placed these funds in escrow. On October 5, 2004, the Operating Partnership purchased the notes for a total price of approximately $1.1 billion, which included $27 million related to consent payments.

 

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The following table shows the four GulfTerra senior debt obligations affected, including the principal amount of each series of notes tendered, as well as the payment made by the Operating Partnership to complete the tender offers.

 

    

Principal
Amount
Tendered


   Cash payments made by the
Operating Partnership


Description


      Accrued
Interest


   Tender
Price(1)


   Total Price

     (In thousands)

8.50% Senior Subordinated Notes due 2010 (Represents 98.2% of principal amount outstanding)

   $ 212,057    $ 6,209    $ 246,366    $ 252,575

10.625% Senior Subordinated Notes due 2012 (Represents 99.9% of principal amount outstanding)

     133,916      4,901      167,612      172,513

8.50% Senior Subordinated Notes due 2011 (Represents 99.5% of principal amount outstanding)

     319,823      9,364      359,379      368,743

6.25% Senior Notes due 2010 (Represents 99.7% of principal amount outstanding)

     249,250      5,366      274,073      279,439
    

  

  

  

Totals

   $ 915,046    $ 25,840    $ 1,047,430    $ 1,073,270
    

  

  

  


(1) Tender price includes consent payment of $30 per $1,000 principal amount tendered.

 

Multi-Year Revolving Credit Facility . In August 2004, the Operating Partnership entered into a five-year $750 million revolving credit facility that includes a sublimit of $100 million for standby letters of credit. This facility became effective concurrent with the closing of the GulfTerra merger and will mature on September 30, 2009. This facility replaced its then existing $270 million multi-year revolving credit facility and $230 million 364-day revolving credit facility, which were terminated upon the effective date of the new facility. The Operating Partnership’s borrowings under this agreement are unsecured general obligations that are non-recourse to Enterprise Products GP. Enterprise Products Partners has guaranteed repayment of amounts due under this revolving credit facility through an unsecured guarantee.

 

As defined by the credit facility, variable interest rates charged under this facility generally bear interest, at the Operating Partnership’s election at the time of each borrowing, at (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus ½% or (2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate.

 

This revolving credit facility contains various covenants related to Enterprise Products Partners’ ability to incur certain indebtedness, grant certain liens, enter into certain merger or consolidation transactions, and make certain investments. The loan agreement also required Enterprise Products Partners to satisfy certain financial covenants at the end of each fiscal quarter. Enterprise Products Partners was in compliance with these covenants at March 31, 2005 and December 31, 2004.

 

Senior Notes A, B, C and D . These fixed-rate notes are an unsecured obligation of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. They are senior to any future subordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to Enterprise Products GP. Enterprise Products Partners has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes are subject to make-whole redemption rights and were issued under an indenture containing certain covenants. These covenants restrict its ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. Enterprise Products Partners was in compliance with these covenants at March 31, 2005 and December 31, 2004. On March 15, 2005, the Operating Partnership repaid the $350 million in indebtedness outstanding under Senior Notes A, using the proceeds it received from its issuance of Senior Notes I and J.

 

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Senior Notes E, F, G and H . On September 23, 2004, the Operating Partnership priced a private offering of an aggregate of $2 billion in principal amount of senior unsecured notes in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended. On October 4, 2004, these notes were issued. The interest rate, principal amount and net proceeds, before expenses, for each senior note in this offering are shown in the following table:

 

Senior Notes Issued


   Fixed
Interest
Rate


    Principal
Amount


   Bond
Discount


   Proceeds to
Enterprise
Products Partners,
Before Expenses


     (Dollars in thousands)

Senior Notes E, due October 2007

   4.000 %   $ 500,000    $ 2,140    $ 497,860

Senior Notes F, due October 2009

   4.625 %     500,000      4,405      495,595

Senior Notes G, due October 2014

   5.600 %     650,000      4,784      645,216

Senior Notes H, due October 2034

   6.650 %     350,000      4,203      345,797
          

  

  

Totals

         $ 2,000,000    $ 15,532    $ 1,984,468
          

  

  

 

The net proceeds from this offering were used to reduce debt amounts outstanding under the Operating Partnership’s $2.25 billion 364-day acquisition credit facility that was used to partially fund the GulfTerra merger on September 30, 2004.

 

These fixed-rate notes are unsecured obligations of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to Enterprise Products GP. Enterprise Products Partners has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes were issued under an indenture containing certain covenants, which restrict its ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. Enterprise Products Partners was in compliance with these covenants at March 31, 2005 and December 31, 2004.

 

On January 24, 2005, the Operating Partnership filed a registration statement for an offer to exchange these notes for registered debt securities with identical terms. The exchange of notes was completed in March, 2005.

 

Senior Notes I and J . On March 1, 2005, the Operating Partnership sold $500 million in principal amount of senior notes in a private offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes (Senior Notes I) were issued at 99.379% of their principal amount and have fixed-rate interest of 5.00% and a maturity date of March 1, 2015. The 30-year notes (Senior Notes J) were issued at 98.691% of their principal amount and have fixed-rate interest of 5.75% and a maturity date of March 1, 2035. The Operating Partnership used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A, which were due on March 15, 2005, and the remaining proceeds were used for general partnership purposes, including the temporary repayment of indebtedness outstanding under the multi-year revolving credit facility.

 

These fixed-rate notes are unsecured obligations of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to Enterprise Products GP. Enterprise Products Partners has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes were issued under an indenture containing certain covenants, which restrict its ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. Enterprise Products Partners was in compliance with these covenants at March 31, 2005.

 

Senior Notes K . On June 1, 2005, the Operating Partnership sold $500 million in principal amount five-year senior unsecured notes. The notes were issued at 99.834% of their principal amount and have a fixed-rate interest

 

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of 4.95% and a maturity date of June 1, 2010. The Operating Partnership used the net proceeds from the issuance of Senior Notes K to temporarily reduce borrowings outstanding under its multi-year revolving credit facility and for general partnership purposes, including capital expenditures and acquisitions.

 

These fixed-rate notes are unsecured obligations of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to Enterprise Products GP. Enterprise Products Partners has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes were issued under an indenture containing certain covenants, which restrict its ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. Enterprise Products Partners was in compliance with these covenants at March 31, 2005.

 

Pascagoula MBFC Loan . In connection with the construction of its Pascagoula, Mississippi natural gas processing plant, the Operating Partnership entered into a ten-year fixed-rate loan with the Mississippi Business Finance Corporation, or MBFC. This loan is subject to a make-whole redemption right and is guaranteed by Enterprise Products Partners through an unsecured and unsubordinated guarantee. The Pascagoula MBFC Loan contains certain covenants including the maintenance of appropriate levels of insurance on the Pascagoula facility. Enterprise Products Partners was in compliance with the covenants at March 31, 2005 and December 31, 2004.

 

The indenture agreement for this loan contains an acceleration clause whereby if its credit rating by Moody’s declines below Baa3 in combination with its credit rating at Standard & Poor’s remaining at BB+ or below, the $54 million principal balance of this loan, together with all accrued and unpaid interest would become immediately due and payable 120 days following such event. If such an event occurred, Enterprise Products Partners would have to either redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to support its obligation under this loan.

 

Industrial Development Revenue Bonds . In April 2004, Petal Gas Storage L.L.C., or Petal, a wholly owned subsidiary of GulfTerra, borrowed $52 million from the MBFC pursuant to a loan agreement between Petal and the MBFC. On the same date, the MBFC issued $52 million in Industrial Development Revenue Bonds to another wholly owned subsidiary of GulfTerra. The loan agreement and the Industrial Development Revenue Bonds have identical fixed interest rates of 6.25% and maturities of fifteen years. The bonds and the associated tax exemptions are authorized under the Mississippi Business Finance Act. Petal may repay the loan agreement without penalty and, thus, cause the Industrial Development Revenue Bonds to be redeemed, any time after one year from their date of issue. Enterprise Products Partners has netted the loan amount and the bond amount of $52 million on its consolidated balance sheets at March 31, 2005 and December 31, 2004. Additionally, Enterprise Products Partners has netted the interest payable and interest receivable amount of $3.0 million and $2.2 million on its consolidated balance sheet at March 31, 2005 and December 31, 2004. Beginning in the fourth quarter of 2004, Enterprise Products Partners also netted the quarterly interest expense and interest income amounts of $0.8 million attributable to these instruments on its Statements of Consolidated Operations. Enterprise Products Partners’ presentation of the Industrial Development Revenue Bonds is reflected in accordance with the provisions of FIN No. 39, “ Offsetting of Amounts Related to Certain Contracts ”, and SFAS No. 140, “ Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities ”, since Enterprise Products Partners has the ability and intent to offset these items.

 

Loss Due to Write-off of Unamortized Debt Issuance Costs . As a result of terminating its 364-day revolving credit facility and its previous multi-year revolving credit facility on September 30, 2004, Enterprise Products Partners expensed $0.7 million of unamortized debt issuance costs for the year ended December 31, 2004.

 

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Information regarding variable interest rates paid

 

The following table shows the range of interest rates paid and weighted-average interest rate paid on its variable-rate debt obligations during the three months ended March 31, 2005.

 

     Range of Interest
Rates Paid


   Weighted-average
Interest Rate Paid


364-Day Acquisition Credit Facility

   3.25% to 3.40%    3.30%

Multi-Year Revolving Credit Facility

   3.22% to 5.50%    3.42%

 

Consolidated Debt Maturity Table

 

The following table shows scheduled maturities of the principal amounts of its debt obligations for the next 5 years and in total thereafter.

 

     (In thousands)

Fiscal 2005

   $ 29,000

Fiscal 2007

     500,000

Fiscal 2009

     800,000

Thereafter

     2,859,719
    

Total scheduled principal to be repaid

   $ 4,188,719
    

 

Joint Venture Debt Obligations

 

Enterprise Products Partners has ownership interests in three joint ventures having long-term debt obligations. The following table shows (i) its ownership interest in each entity at March 31, 2005, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate at March 31, 2005, on a 100% basis to the joint venture and (iii) the corresponding scheduled maturities of such long-term debt (dollars in thousands).

 

    Enterprise
Products
Partners’
Ownership
Interest


   

Total


  Scheduled Maturities of Long-Term Debt

        2005

  2006

  2007

  2008

  2009

  After
2009


Cameron Highway(1)

  50.0 %   $ 325,000         $ 8,125   $ 32,500   $ 192,375   $ 16,000   $ 76,000

Poseidon

  36.0 %     104,000                       104,000            

Evangeline

  49.5 %     35,650   $ 5,000     5,000     5,000     5,000     5,000     10,650
         

 

 

 

 

 

 

Total

        $ 464,650   $ 5,000   $ 13,125   $ 37,500   $ 301,375   $ 21,000   $ 86,650
         

 

 

 

 

 

 


(1) The scheduled maturities for Cameron Highway assume that the construction loan will be converted into a term loan by July 2005 and scheduled repayments will begin on December 31, 2006.

 

The following is a summary of the significant aspects of the debt obligations of Enterprise Products Partners’ unconsolidated affiliates.

 

Cameron Highway . In July 2003, Cameron Highway entered into a $325 million project loan facility, consisting of a $225 million construction loan and $100 million of senior secured notes, to finance a substantial portion of the cost to construct the Cameron Highway oil pipeline. At March 31, 2005, Cameron Highway had $225 million outstanding under its construction loan at an average interest rate of 5.56% and $100 million outstanding under its senior secured notes at an average interest rate of 7.36%.

 

In June 2005, Cameron Highway amended and restated its credit agreement and borrowed the full amount thereunder of $415 million. The loan has a maturity date of June 28, 2006 and is secured by (1) mortgages on and pledges of substantially all of the assets of Cameron Highway, (2) mortgages on and pledges of certain assets related to certain rights of way and pipeline assets of an indirect wholly owned subsidiary of Enterprise Products Partners that serves as the operator of the Cameron Highway Pipeline, (3) pledges by subsidiaries of Enterprise

 

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Products Partners and Valero of their partnership interests in Cameron Highway, and (4) letters of credit in the amount of $14 million each issued by the Operating Partnership and Valero. Except for the foregoing, the lenders do not have any recourse against the assets of Enterprise Products Partners or any of its subsidiaries under the amended and restated credit agreement.

 

A portion of the proceeds of the loan were used to refinance Cameron Highway’s existing debt, having an aggregate outstanding principal amount of $325 million, and to make cash distributions to the owners of Cameron Highway. In connection with this refinancing, Cameron Highway is expected to incur approximately $22 million in one-time make whole premiums and related fees and costs, which include $6.3 million of non-cash charges. Enterprise Products Partners’ equity earnings from Cameron Highway for the three and six months ended June 30, 2005 will be reduced by its 50% share of such costs.

 

The loan bears interest at a variable rate at either (at the election of Cameron Highway from time to time): (1) the greater of (a) the Prime Rate or (b) the Federal Funds Rate plus 0.5%, or (2) the Adjusted LIBO Rate plus, in each case, the Applicable Margin.

 

Deepwater Gateway . In August 2002, Deepwater Gateway, Enterprise Products Partners’ unconsolidated affiliate which owns the Marco Polo tension-leg platform, obtained a $155 million project finance loan to finance a substantial portion of the cost to construct the Marco Polo tension-leg platform and related facilities. Construction of the Marco Polo tension-leg platform was completed during the first quarter of 2004, and in June 2004, Deepwater Gateway converted the project finance loan into a term loan maturing in June 2009.

 

In accordance with terms of the credit agreement, Deepwater Gateway had the right to repay the principal amount plus any accrued interest due under its term loan at any time without penalty. Deepwater Gateway paid its term loan in full on March 29, 2005. Enterprise Products Partners and its 50% joint venture partner in Deepwater Gateway, Cal Dive, made cash contributions of approximately $72 million each to Deepwater Gateway to fund the repayment.

 

Poseidon . Poseidon is party to a $170 million revolving credit facility which matures in January 2008. The interest rates Poseidon is charged on balances outstanding under its revolving credit facility are variable and depend on its ratio of total debt to earnings before interest, taxes, depreciation and amortization. This credit agreement is secured by substantially all of Poseidon’s assets. As of March 31, 2005, Poseidon had $104 million outstanding under its revolving credit facility at an average interest rate of 4.69%.

 

Evangeline . At December 31, 2004, long-term debt for Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively, or Evangeline, consisted of (i) $28.2 million in principal amount of 9.9% fixed-rate Series B senior secured notes that are due in December 2010 and (ii) a $7.5 million subordinated note payable. The Series B senior secured notes are collateralized by Evangeline’s property, plant and equipment; proceeds from a gas sales contract; and by a debt service 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 incurred the subordinated note payable in connection with its acquisition of a contract-based intangible asset in the early 1990s. This 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. In general, interest accrues on the subordinated note at a variable-rate based on LIBOR plus ½%. The variable interest rate paid on this debt at March 31, 2005 was 2.92%.

 

Credit Ratings

 

Enterprise Products Partners’ current corporate credit ratings are Baa3 (investment grade) with a stable outlook as rated by Moody’s Investor Services; BB+ (non-investment grade) with a stable outlook as rated by Standard and Poor’s; and BBB- (investment grade) with a stable outlook by Fitch ratings.

 

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Depending on Enterprise Products Partners’ future operating results, these credit rating agencies may view its current levels of debt negatively. If one or more of these credit rating agencies were to downgrade its credit standing, Enterprise Products Partners could experience an increase in its borrowing costs, difficulty accessing capital markets or a reduction in the market price of its common units. Such a development could adversely affect its ability to obtain financing for working capital, capital expenditures, acquisitions and to refinance indebtedness.

 

Additionally, if Enterprise Products Partners’ credit rating by Moody’s declines below Baa3 in combination with its credit rating at Standard & Poor’s remaining at BB+ or below, the $54 million principal balance of its Pascagoula MBFC Loan, and all related accrued and unpaid interest would become immediately due and payable 120 days following such event. If such an event occurred, Enterprise Products Partners would have to redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to support its obligation under the Pascagoula MBFC Loan.

 

Capital Spending

 

Enterprise Products Partners has a number of ongoing capital projects, including those it assumed as a result of the GulfTerra merger. The following table summarizes its capital spending by activity for the periods indicated:

 

     For Year Ended December 31,

   For the Three
Months Ended
March 31,


     2004

    2003

   2002

   2005

   2004

     (Dollars in thousands)          

Capital spending for business combinations:

                                   

GulfTerra merger (step two transactions):

                                   

Cash payments to El Paso

   $ 500,000                             

Transaction fees and other direct costs

     24,032                             

Cash received from GulfTerra

     (40,313 )                           
    


                          

Net cash payments

     483,719                             

Value of non-cash consideration issued or granted

     2,910,771                             
    


                          

Total GulfTerra merger step two consideration

     3,394,490                             

GulfTerra merger (step three transactions):

                                   

Cash payments to El Paso

     155,277                             

Mid-America and Seminole pipelines

                  $ 1,182,946              

Propylene fractionation and hydrocarbon storage assets

                    368,636              

Indirect interests in the Indian Springs natural gas gathering and processing assets

                         $ 74,855       

Additional ownership interests in Dixie

                           68,049       

Other business combinations

     85,851     $ 37,348      69,145      7,574       
    


 

  

  

      

Total capital spending related to business combinations

     3,635,618       37,348      1,620,727      150,478       
    


 

  

  

      

Capital spending for property, plant and equipment:

                                   

Growth capital projects

     114,419       125,600      64,934      150,738    $ 10,841

Sustaining capital projects

     32,509       20,313      7,201      15,550      4,162
    


 

  

  

  

Total capital spending for property, plant and equipment

     146,928       145,913      72,135      166,288      15,003
    


 

  

  

  

Capital spending attributable to unconsolidated affiliates:

                                   

Investments in and advances to unconsolidated affiliates

     64,412       471,927      13,651      88,634      818
    


 

  

  

  

Total capital spending

   $ 3,846,958     $ 655,188    $ 1,706,513    $ 405,400    $ 15,821
    


 

  

  

  

 

The preceding table reflects capital spending of $3.5 billion for the GulfTerra merger in 2004, $425 million for Enterprise Products Partners’ investment in GulfTerra’s general partner in 2003 and $1.2 billion for its acquisition of the Mid-America and Seminole pipelines in 2002. Enterprise Products Partners’ capital spending for property, plant and equipment is reflected net of contributions in aid of construction costs of $8.9 million, $0.9 million and $4 million during 2004, 2003 and 2002, respectively. Contributions in aid of construction costs for the three months ended March 31, 2005 and 2004, were $8.9 million and $0.2 million, respectively.

 

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Enterprise Products Partners is committed to the long-term growth and viability of its company. Part of its business strategy involves expansion through business combinations, growth capital projects and investments in joint ventures. In recent years, major oil and gas companies have sold non-strategic assets in the midstream energy sector in which Enterprise Products Partners operates. Enterprise Products Partners forecasts that this trend will continue, and expects independent oil and natural gas companies to consider similar divestitures. Enterprise Products Partners’ management continues to analyze potential acquisitions, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions. Enterprise Products Partners believes that it is positioned to continue to grow through acquisitions that will expand its system of assets and through growth capital projects. The combination of its operations with those of GulfTerra provides Enterprise Products Partners with incremental growth opportunities for both onshore and offshore projects. Enterprise Products Partners currently estimates that its capital spending over the next two to three years could approximate up to $2 billion, primarily for growth projects in the Gulf of Mexico and Western regions of North America. Of this amount, Enterprise Products Partners expects to spend approximately $970 million during 2005.

 

The ability to execute its growth strategy and complete its projects is dependent upon its access to the capital necessary to fund projects and acquisitions. Enterprise Products Partners’ success with capital raising efforts, including the formation of joint ventures to share costs and risks, continues to be the critical factor which determines how much it actually spends. Enterprise Products Partners believes its access to capital resources is sufficient to meet the demands of its current and future operating growth needs, and although it currently intends to make the forecasted expenditures discussed below, it may adjust the timing and amounts of projected expenditures as necessary to adapt to changes in the capital markets.

 

Enterprise Products Partners estimates its forecasted expenditures based upon its strategic operating and growth plans, which are also dependent upon its ability to provide capital from operating cash flows or otherwise obtain the capital necessary to accomplish its operating and growth objectives. These estimates may change due to factors beyond its control, such as weather related issues, changes in supplier prices or poor economic conditions. Further, estimates may change as a result of decisions made at a later date, which may include acquisitions or decisions to take on additional partners.

 

As noted, Enterprise Products Partners estimates its capital spending for property, plant and equipment during 2005 to approximate $970 million, which includes estimated expenditures of $900 million for growth capital projects and acquisitions and approximately $70 million for sustaining capital expenditures which result from improvements to and major renewals of existing assets. Of the $900 million in forecast expenditures on growth capital projects and acquisitions, the following table summarizes such expenditures for announced acquisitions and significant capital projects during 2005 (in millions of dollars):

 

Growth Capital Projects:

      

Independence Hub Platform

   $ 160.3

Independence Trail Pipeline System

     159.8

Constitution Gathering System

     126.7

San Juan Optimization Project

     30.0

NGL Expansion Projects

     29.7

Iso-Octane Conversion Project

     12.7

Petal Conversion Project

     11.9

Acquisitions:

      

Additional interests in Dixie Pipeline Company(1)

     70.9

Indian Springs natural gas gathering and processing assets(1)

     74.5
    

Total

   $ 676.5
    


(1) For information regarding these acquisitions, please read “—Recent Developments.”

 

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Enterprise Products Partners also expects to invest approximately $7.5 million in the capital projects of its unconsolidated affiliates during 2005. As of March 31, 2005 and December 31, 2004, Enterprise Products Partners had approximately $227.3 million and $70 million, respectively, in outstanding purchase commitments related to capital projects, the majority of which pertain to pipeline and platform growth projects in the Gulf of Mexico that are expected to be placed in service during 2005 and 2006.

 

Significant Announced Growth Capital Projects

 

Prior to the GulfTerra merger, GulfTerra had a number of midstream energy projects underway. In addition, Enterprise Products Partners has announced various new growth capital projects that are currently underway. The following is a discussion of Enterprise Products Partners’ significant growth capital projects, including those acquired with in the GulfTerra merger:

 

Independence Hub Platform and Independence Trail Pipeline System . In November 2004, Enterprise Products Partners entered into an agreement with the Atwater Valley Producers Group (consisting of Anadarko, Dominion, Kerr-McGee, Spinnaker and Devon) for the dedication, processing and gathering of natural gas and condensate production from several natural gas fields in the Atwater Valley, DeSoto Canyon and Lloyd Ridge areas (collectively, the anchor fields) of the deepwater Gulf of Mexico. Enterprise Products Partners will design, construct, and own Independence Hub, a 105-foot deep-draft, semi-submersible platform with a two-level production deck, which will be capable of processing 850 MMcf/d of natural gas. The platform, which is estimated to cost approximately $385 million, will be operated by Anadarko, and is designed to process production from its anchor fields and has excess payload capacity to support ten additional pipeline risers. In December 2004, Enterprise Products Partners entered into an agreement with Cal Dive to sell them a 20% indirect interest in the Independence Hub platform. Under the terms of the agreement, Enterprise Products Partners will have access to Cal Dive’s fleet of vessels, which will assist Enterprise Products Partners in the construction of the Independence Hub platform and the related export pipeline.

 

The Independence Hub platform will be located on Mississippi Canyon Block 920, in a water depth of 8,000 feet. This location was selected for the permanently anchored platform based on favorable seafloor conditions and proximity to the identified anchor fields. First production is expected in 2007. Under the terms of the agreement, the production fields served by the Independence Hub platform will include the nine dedicated anchor fields in addition to future discoveries on surrounding undeveloped blocks.

 

Additionally, Enterprise Products Partners will construct, own, and operate the 134-mile Independence Trail natural gas pipeline system, which will have a throughput capacity of approximately 850 MMcf/d of natural gas. The pipeline system, which is estimated to cost $280 million, will transport production from the Independence Hub platform to the Tennessee Gas Pipeline. Enterprise Products Partners entered into an agreement with Tennessee Gas Pipeline under which they will pay Enterprise Products Partners $15 million for contributions in aid of construction to connect the Independence Trail natural gas pipeline system to their pipeline system. In November 2004, Tennessee Gas Pipeline reimbursed Enterprise Products Partners $7 million for construction costs incurred. The balance of $8 million would be reimbursed by Tennessee Gas Pipeline when additional costs are incurred and is contingent upon its completion of the Independence Trail project, which is expected during 2006.

 

Constitution Gathering System . In July 2004, GulfTerra entered into a definitive agreement to construct, own, and operate oil and natural gas pipelines to provide production gathering services for the Constitution field, which is 100% owned by Kerr-McGee. The Constitution field is located at a depth of 5,300 feet in Green Canyon Blocks 679 and 680 in the Central Gulf of Mexico. The new $53.4 million natural gas pipeline will be a 32-mile, 16-inch pipeline with a transport capacity of up to 200 MMcf/d and will connect to its existing Anaconda Gathering System. The new $76.2 million oil pipeline will be a 70-mile, 16-inch pipeline with a minimum transport capacity of 80 MBbls/d that will connect with the Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System at its Ship Shoal 332B platform. These pipelines are expected to start transporting volumes scheduled in the first half of 2006.

 

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San Juan Optimization Project . In May 2003, Enterprise Products Partners commenced a project relating to its San Juan Basin assets. This project, which is estimated to cost approximately $43 million, is expected to be completed in stages through 2006 and will result in increased capacity of up to 130 MMcf/d on its San Juan natural gas gathering system and increased market opportunities through a new interconnect at the tailgate of its Chaco plant.

 

Rocky Mountain NGL pipeline expansion and related NGL fractionation projects . In January 2005, Enterprise Products Partners started a project to expand its Mont Belvieu NGL fractionator to accommodate increased production of NGLs being transported to Mont Belvieu from the Rocky Mountain area. Enterprise Products Partners Mont Belvieu facility’s current fractionation capacity is up to 210 MBbls/d of mixed NGLs. This project, which is expected to be completed in the first quarter of 2006 at an estimated total cost of $34.2 million, will increase total fractionation capacity at this facility by 15 MBbls/d and reduce its energy costs. Additionally, Enterprise Products Partners has announced that it plans to construct a new NGL fractionator, designed to handle up to 75 MBbls/d of mixed NGLs, located at the interconnection of the Mid-America pipeline system and the Seminole pipeline system near Hobbs, New Mexico.

 

Currently, the Rocky Mountain segment of its Mid-America pipeline system transports up to 225 MBbls/d of NGLs from the major producing basins in Wyoming, Utah, Colorado and New Mexico to the Hobbs station on the Texas-New Mexico border. The Western Expansion Project would increase the capacity of this pipeline to 275 MBbls/d. Permitting, engineering and design work are in progress. Enterprise Products Partners submitted a draft environmental assessment and plan of development to the appropriate regulatory agencies during the first quarter of 2005. Contingent upon receiving all required permits and regulatory approvals, construction could begin as early as the fourth quarter of 2005.

 

Iso-Octane Conversion Project . As a result of environmental concerns related to MTBE, Enterprise Products Partners is currently in the process of modifying its BEF facility to produce iso-octane, a motor gasoline octane enhancement additive derived from isobutane. Enterprise Products Partners expects iso-octane to be in demand by refiners to replace the amount of octane that is lost as a result of MTBE being eliminated as a motor gasoline blendstock. Depending on the outcome of various factors (including pending federal legislation) the facility may be further modified in the future to produce alkylate.

 

Petal Conversion Project . In the third quarter of 2004, Enterprise Products Partners began to convert an existing brine well at its existing propane storage complex in Hattiesburg, Mississippi to natural gas service. This conversion, which is expected to cost $18 million, will create a new natural gas storage cavern with 1.8 billion cubic feet, or Bcf of working gas capacity that will be integrated with its existing Petal natural gas storage facility. Enterprise Products Partners expects to have the cavern in service during the second quarter of 2005. Enterprise Products Partners has executed long-term storage agreements with BP for the entire capacity of the new natural gas storage cavern.

 

Purchase options associated with retained leases

 

EPCO contributed various equipment leases to Enterprise Products Partners at its formation in 1998 for which EPCO has retained the cash payment obligations. EPCO has assigned to Enterprise Products Partners the purchase options associated with such retained leases. During 2003, Enterprise Products Partners exercised its option to purchase an isomerization unit and in October 2004 purchased the unit at a cost of $15 million, which approximated fair value. Additionally, in December 2004, Enterprise Products Partners purchased equipment related to the isomerization unit for $2.8 million pursuant to its purchase option. Should Enterprise Products Partners decide to exercise the remaining purchase options associated with these retained leases (which are also at fair value), an additional $2.3 million would be payable in 2008 and $3.1 million in 2016.

 

Pipeline Integrity Costs

 

Enterprise Products Partners 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

 

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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 new regulations for hazardous liquid pipelines, Enterprise Products Partners developed a pipeline integrity management program in 2002. In connection with the new regulations for natural gas pipelines, Enterprise Products Partners developed a pipeline integrity management program in 2004.

 

During the first quarter of 2005, Enterprise Products Partners spent approximately $5.4 million to comply with these new regulations, of which $4.3 million was recorded as an operating expense with the remaining $1.1 million being capitalized. During 2004, Enterprise Products Partners spent approximately $22.4 million to comply with these new regulations, of which $12.2 million was recorded as an operating expense of its NGL Pipelines & Services segment and $2.7 million was recorded as an operating expense of its Onshore Natural Gas Pipelines & Services segment. The remaining $7.5 million Enterprise Products Partners spent during 2004 to comply with the new regulations was capitalized. Based on information currently available, its cash outlays for its pipeline integrity program associated with these new regulations are estimated to be approximately $46.6 million for the remainder of 2005.

 

The forecasted cost for 2005 is net of an indemnification Enterprise Products Partners will receive from El Paso. In April 2002, GulfTerra acquired several midstream assets located in Texas and New Mexico from El Paso (the “EPN Holdings” acquisition). The assets acquired included the Texas Intrastate System, the Permian Basin System and the Indian Basin gas processing facility. Pursuant to an amended purchase and sale agreement between GulfTerra and El Paso for these assets, El Paso agreed to indemnify GulfTerra against all pipeline integrity costs incurred (whether paid or payable) with respect to the assets acquired in the EPN Holdings acquisition for each of the years ending December 31, 2005, 2006 and 2007, to the extent that such annual costs exceed $3.3 million; however, the amount reimbursable by El Paso for 2005, 2006 and 2007 shall not exceed $50.2 million.

 

Contractual Obligations

 

With regards to Enterprise Products Partners’ material contractual obligations, there have been no significant changes outside of the ordinary course of business since December 31, 2004. The following table summarizes Enterprise Products Partners’ contractual obligations at December 31, 2004 (dollars in thousands):

 

     Payment or Settlement Due by Period

Contractual Obligations


   Total

   Less than 1
Year


   1-3 Years

   3-5 Years

  

More than

5 Years


          (2005)    (2006-2007)    (2008-2009)    Beyond 2009

Scheduled maturities of long-term debt (1)

   $ 4,288,698    $ 15,000    $ 500,000    $ 821,000    $ 2,952,698

Estimated cash payments for interest (2)

   $ 2,666,248    $ 217,925    $ 413,253    $ 370,276    $ 1,664,794

Operating lease obligations (3)

   $ 88,899    $ 15,012    $ 25,622    $ 14,914    $ 33,351

Purchase obligations: (4)

                                  

Product purchase commitments:(5)

                                  

Estimated payment obligations:

                                  

Natural gas

   $ 1,160,829    $ 165,120    $ 284,266    $ 284,655    $ 426,788

NGLs

   $ 174,281    $ 42,664    $ 21,936    $ 21,936    $ 87,745

Petrochemicals

   $ 1,791,983    $ 1,010,907    $ 774,828    $ 6,248       

Other

   $ 166,706    $ 41,706    $ 62,271    $ 46,845    $ 15,884

Underlying major volume commitments:

                                  

Natural gas (in BBtus)

     149,705      21,855      36,500      36,550      54,800

NGLs (in MBbls)

     5,657      1,267      732      732      2,926

Petrochemicals (in MBbls)

     27,294      15,559      11,646      89       

Service payment commitments(6)

   $ 7,580    $ 4,906    $ 2,674              

Capital expenditure commitment(7)

   $ 69,288    $ 69,288                     

Other long-term liabilities, as reflected on its Consolidated Balance Sheet (8)

   $ 63,521           $ 15,846    $ 10,385    $ 37,290

 

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(1) Enterprise Products Partners has long and short-term payment obligations under credit agreements such as its senior notes and revolving credit facilities. Amounts shown in the table represent its scheduled future maturities of long-term debt principal (including current maturities) for the periods indicated. In accordance with SFAS No. 6, “Classification of Short-Term Obligations Expected to Be Refinanced,” the scheduled maturities of debt presented in the table reflect (i) its refinancing of Senior Notes A with proceeds from its Senior Notes I and J in March 2005 and (ii) the repayment of its 364-day acquisition credit facility using proceeds from an equity offering completed in February 2005. For additional information regarding its debt obligations, please read “—Debt Obligations.”
(2) Amounts shown in the table above represent our estimated cash interest payments for long-term debt (including current maturities thereof) for the periods indicated. Our projected cash interest payments for variable interest rate debt obligations were calculated by multiplying the weighted-average variable interest rate paid during 2004 (please read “—Debt Obligations”) for our variable rate debt obligations outstanding at December 31, 2004 by the principal amount outstanding under each such variable interest rate debt obligation at December 31, 2004. The related estimated payments of variable interest by period is: $48.1 million in total, $11.2 million for 2005, a combined $19.6 million for 2006 and 2007 and a combined $17.2 million for 2008 and 2009. Our projected cash interest payments for fixed interest rate debt obligations includes our estimate of potential future cash outflows associated with interest rate swap agreements whereby we have exchanged fixed interest rates for variable interest rates (please read “—Quantitive and Qualitative Disclosures about Market Risk—Interest Rate Risk Hedging Program” for a discussion of these interest rate swap agreements). Our internal estimates of long-term interest rates indicate that variable interest rates may exceed the fixed interest rates of the debt obligations underlying our interest rate swap agreements. If this occurs, we would be responsible for payment of the excess of the current variable interest rate over the fixed interest rate of the underlying debt obligation. For conservatism, the amounts shown in the table above do not reflect any cash receipts from interest rate swap agreements when the variable interest rate is less than the fixed interest rate of the underlying debt obligations.
(3) Enterprise Products Partners leases certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the table represent minimum lease payment obligations under its third-party operating leases with terms in excess of one year for the periods indicated. For addition information regarding its operating lease commitments, please read Note 15 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.
(4) Enterprise Products Partners defines a purchase obligation as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on Enterprise Products Partners that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions.
(5) Enterprise Products Partners has long and short-term product purchase obligations for NGLs, petrochemicals and natural gas with third-party suppliers. The prices that Enterprise Products Partners is obligated to pay under these contracts approximate market prices at the time it takes delivery of the volumes. Amounts shown in the table represent its volume commitments and estimated payment obligations under these contracts for the periods indicated. Enterprise Products Partners estimated future payment obligations are based on the contractual price under each contract for purchases made at December 31, 2004 applied to all future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery.
(6) Enterprise Products Partners has long and short-term commitments to pay third-party service providers for services such as maintenance agreements. Enterprise Products Partners contractual payment obligations vary by contract. The table shows its future payment obligations under these service contracts.
(7) Enterprise Products Partners has short-term payment obligations relating to capital projects it has initiated and are also responsible for its share of such obligations associated with the capital projects of its unconsolidated affiliates. These commitments represent unconditional payment obligations that Enterprise Products Partners or its unconsolidated affiliates have agreed to pay vendors for services rendered or products ordered.

 

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(8) Enterprise Products Partners has recorded long-term liabilities on its balance sheet reflecting amounts it expects to pay in future periods beyond one year. These liabilities primarily relate to reserves for asset retirement obligations, environmental liabilities and other amounts. Amounts shown in the table represent its best estimate as to the timing of payments based on available information.

 

The operating lease commitments shown in the preceding table exclude the non-cash, related party expense associated with various equipment leases contributed to Enterprise Products Partners by EPCO at its formation for which EPCO has retained the liability. Such retained leases are accounted for as operating leases by EPCO. EPCO’s minimum future rental payments under these leases are $2.1 million for each of the years 2005 through 2008, $0.7 million for each of the years 2009 through 2015 and $0.3 million for 2016. For additional information regarding the retained leases, please read “Certain Relationships and Related Party Transactions.”

 

Recent Accounting Developments

 

SFAS No. 123(R), “Share-Based Payment.” This accounting guidance, which is applicable for public companies the first fiscal year beginning on or after June 15, 2005, replaces SFAS No. 123, “Accounting for Stock-Based Compensation” and supersedes APB No. 25, “Accounting for Stock Issued to Employees.” This Statement eliminates the ability to account for share-based compensation transactions using APB No. 25, and generally requires instead that such transactions be accounted for using a fair-value-based method. We are continuing to evaluate the provisions of SFAS No. 123(R) and will adopt the standard on January 1, 2006. Upon the required effective date, we will apply this statement using a modified version of prospective application as described in the standard.

 

On March 29, 2005, the SEC issued Staff Accounting Bulletin (“SAB”) 107 to provide public companies additional guidance in applying the provisions of SFAS No. 123(R). Among other things, SAB 107 describes the SEC staff’s expectations in determining the assumptions that underlie the fair value estimates and discusses the interaction of SFAS No. 123(R) with certain existing SEC guidance. The guidance is also beneficial to users of financial statements in analyzing the information provided under SFAS No. 123(R). We will apply the provisions of SAB 107 upon the adoption of SFAS No. 123(R).

 

FIN 46(R)-5, “Implicit Variable Interests Under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities.” On March 3, 2005, the FASB issued this guidance to address whether a reporting enterprise has an implicit variable interest in a variable interest entity or potential variable interest entity when specific conditions exist. FIN 46(R)-5 covers issues that commonly arise in leasing arrangements among related parties, as well as other types of arrangements involving both related and unrelated parties. Implicit variable interests are implied financial interests in an entity’s net assets exclusive of variable interests. An implicit variable interest acts the same as in an explicit variable interest except it involves the absorbing and (or) receiving of variability indirectly from the entity (rather than directly). The identification of an implicit variable interest is a matter of judgment that depends on the relevant facts and circumstances. This guidance is effective for our fiscal quarter ending June 30, 2005. We are continuing to evaluate the provisions of FIN 46(R)-5, which may affect certain non-material leases of office space from a related party.

 

FIN 47, “Accounting for Conditional Asset Retirement Obligations.” Under SFAS No. 143, a company must record a liability for its legal obligations stemming from the eventual retirement of its tangible long-lived assets, whether that obligation results from the acquisition, construction, or development of the asset. However, many companies have not recorded a liability, concluding that either (1) the conditional nature of the obligation does not create a liability until the retirement activity occurs or (2) the timing and/or the method of settling the obligation is unknown. This Interpretation concludes otherwise. If required legally, an obligation associated with the asset’s retirement is inevitable even though uncertainties exist about the timing and/or method of settling the obligation. According to the Interpretation, these uncertainties affect the fair value of the liability, rather than obviate the need to record one at all. Additionally, the ability of a company to postpone indefinitely settlement of the obligation, or to sell the asset prior to its retirement, does not relieve a company of its present duty to settle

 

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the obligation. We are currently studying the effects of the adoption of this Interpretation which we will adopt in December 2005.

 

Critical Accounting Policies

 

In its financial reporting process, Enterprise Products Partners employs methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of its 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 describes the estimation risk underlying its 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. Enterprise Products Partners uses the straight-line method to depreciate the majority of its property, plant and equipment, which results in depreciation expense being incurred evenly over the life of the assets. Enterprise Products Partners estimates depreciation based on the estimated useful lives and residual values of its assets. As of the time it places its assets in service, Enterprise Products Partners believes its estimates are accurate. However, circumstances in the future may develop which would cause Enterprise Products Partners to change these estimates and in turn would change its 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 March 31, 2005 and December 31, 2004, the net book value of its property, plant and equipment was $8.1 billion and $7.8 billion, respectively. Enterprise Products Partners recorded $161 million and $101 million in depreciation expense during 2004 and 2003, respectively. Depreciation expense for the three months ended March 31, 2005 and 2004 was $78.9 million and $26.8 million, respectively. A significant portion of the period-to-period increases in depreciation expense are attributable to the property, plant and equipment assets Enterprise Products Partners acquired in the GulfTerra merger, which were recorded at their preliminary fair values upon completion of the GulfTerra merger at September 30, 2004. For additional information regarding its property, plant and equipment, please read Notes 1 and 6 of the Notes to Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Measuring recoverability of long-lived assets and equity method investments

 

Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. 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 future expected 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. Enterprise Products Partners’ estimates of such undiscounted cash flows are based on a number of assumptions including anticipated margins and volumes; estimated useful life of the asset or asset group; and salvage values. An impairment charge would be recorded for the excess of the long-lived asset’s carrying value and its fair value, which is based on a series of assumptions similar to those used to derive undiscounted cash flows but incorporating probabilities that reflect a range of possible outcomes and market value and replacement cost estimates.

 

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Equity method investments are evaluated for impairment whenever events or changes in circumstances indicate that there is a loss in value of the investment which is an other than temporary decline. Examples of such events or changes include continued operating losses of 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 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.

 

Due to a deteriorating business environment, BEF evaluated the carrying value of its long-lived assets for impairment during the third quarter of 2003. This review indicated that the carrying value of its long-lived assets exceeded their collective fair value, which resulted in a non-cash impairment charge of $67.5 million. Since BEF was one of its equity investments at that time, its share of this loss was $22.5 million and was recorded as a component of equity in income (loss) of unconsolidated affiliates on its 2003 Statement of Consolidated Operations. As a consolidated subsidiary, BEF continues to review its operations on quarterly basis due to the challenging and uncertain business environment in which it operates.

 

In order to complete the GulfTerra merger, the FTC required Enterprise Products Partners to sell its interest in a Mississippi propane storage facility in which Enterprise Products Partners owned a 50% interest. As a result of its determination of this long-lived asset’s current market value, Enterprise Products Partners recorded a $4 million non-cash asset impairment charge during the third quarter of 2004, which is reflected as a component of operating costs and expenses on its 2004 Statement of Consolidated Operations.

 

Additionally, during 2003 Enterprise Products Partners recorded a $1.2 million asset impairment charge related to its Petal NGL fractionator. This non-cash amount is a component of operating costs and expenses as shown on its 2003 Statement of Consolidated Operations. The Petal NGL fractionation facility was decommissioned in December 2003 after management decided that this older facility did not fit into its long- range plans due to poor economics of continued operations at the site. Enterprise Products Partners continue to own this facility, the carrying value of which has been adjusted to its fair value of approximately $0.1 million.

 

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. Potential intangible assets include intellectual property, such as technology, patents, trademarks and trade names, customer contracts and relationships, and non-compete agreements, as well as other intangible assets. The approach to the valuation of each intangible asset will vary depending upon the nature of the asset, the business in which it is utilized, and the economic returns it is generating or is expected to generate. Enterprise Products Partners recorded intangible assets primarily include the estimated value assigned to certain customer relationships and contract-based assets.

 

Enterprise Products Partners’ customer relationship intangible assets represent the customer base that GulfTerra and the South Texas midstream assets serve through providing services, including natural gas gathering and processing, NGL fractionation and pipeline transportation. These entities conduct the majority of their business through the use of written contracts; thus, the customer relationships represent the rights Enterprise Products Partners owns arising from these contractual agreements. The value of these customer relationships are being amortized using methods that closely resemble the pattern in which the economic benefits of the underlying oil and natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. Enterprise Products Partners’ estimate of the economic life of each resource base is based on a number of factors, including third-party reserve estimates, the economic viability of production and exploration activities and other industry factors.

 

Enterprise Products Partners’ contract-based intangible assets represent the rights it owns arising from contractual agreements in the natural gas and NGL storage operations. A contract-based intangible asset with a

 

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finite useful life is amortized over its estimated useful life, which is the period over which the asset is expected to contribute directly or indirectly to the future cash flows of an entity based on the respective contract terms. Enterprise Products Partners’ estimate of useful life is also based on a number of factors, including (1) the expected use of the asset by the entity, (2) the expected useful life of the related assets (i.e., fractionation facility, pipeline, etc.), (3) any legal, regulatory or contractual provisions, including renewal or extension periods that would cause substantial costs or modifications to existing agreements, (4) the effects of obsolescence, demand, competition, and other economic factors and (5) the level of maintenance required to obtain the expected future cash flows.

 

If its underlying assumptions regarding the useful life or the economic life of the resource base associated with an intangible asset change (either favorably or unfavorably), then Enterprise Products Partners may be required to adjust the amortization period of such asset to reflect any new estimate of its useful life or economic life of the resource base. Such a change would increase or decrease the annual amortization charge associated with the asset at that time. Additionally, if Enterprise Products Partners determines that an intangible asset’s unamortized cost may not be recoverable due to impairment, it may be required to reduce the carrying value and the subsequent useful life of the asset or economic life of the resource base associated with the asset. Any such write-down of the value and unfavorable change in the useful life or economic life associated with the resource base (i.e., amortization period) of an intangible asset would increase operating costs and expenses at that time.

 

At March 31, 2005 and December 31, 2004, the carrying value of Enterprise Products Partners’ intangible asset portfolio was $960.1 million and $980.6 million. Amortization expense associated with Enterprise Products Partners’ intangible assets for the three months ended March 31, 2005 and 2004, was $22.6 million and $3.8 million, respectively. Enterprise Products Partners recorded $33.8 million and $14.8 million in amortization expense associated with its intangible assets during 2004 and 2003, respectively. A significant portion of the period-to-period increases in amortization expense are attributable to the intangible assets Enterprise Products Partners acquired in the GulfTerra merger, which were recorded at their preliminary fair values upon completion of the GulfTerra merger at September 30, 2004. For additional information regarding Enterprise Products Partners’ intangible assets, please read Note 8 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Methods Enterprise Products Partners employs to measure the fair value of goodwill

 

Enterprise Products Partners’ goodwill is attributable to the excess of the purchase price over the fair value of assets acquired and at March 31, 2005, is primarily comprised of $374.3 million associated with the GulfTerra merger which occurred on September 30, 2004, and $73.7 million associated with the purchase of propylene fractionation assets from Diamond-Koch in February 2002. Goodwill is not amortized. Instead, goodwill is tested for impairment at a reporting unit level annually, and more frequently, if circumstances indicate it is more likely than not that the fair value of goodwill is below its carrying amount. The testing of goodwill involves calculating the fair value of a reporting unit, which in turn is based on Enterprise Products Partners’ assumptions regarding the future economic prospects of the reporting unit. If the fair value of the reporting unit (including related goodwill) is less than its book value, a charge to earnings would be required to reduce the carrying value of goodwill to its implied fair value. If its underlying assumptions regarding the future economic prospects of a reporting unit change, this could further impact the fair value of the reporting unit and result in an additional charge to earnings to reduce the carrying value of goodwill.

 

At March 31, 2005 and December 31, 2004, the carrying value of Enterprise Products Partners’ goodwill was $456.7 million and $459.2 million. As a result of the GulfTerra merger, the preliminary value allocated to goodwill is subject to change. For additional information regarding Enterprise Products Partners’ goodwill, please read Note 8 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

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Enterprise Products Partners’ revenue recognition policies and use of estimates for revenues and expenses

 

In general, Enterprise Products Partners recognizes revenue from its customers when all of the following criteria are met (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyer’s price is fixed or determinable and (iv) collectibility is reasonably assured. When the contracts settle (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed), a determination of the necessity of an allowance is made and recorded accordingly. Historically, the consolidated revenues Enterprise Products Partners recorded were not materially based on estimates.

 

However, Enterprise Products Partners’ use of estimates for revenues, as well as its use of estimates for operating costs and other expenses has increased as a result of Commission regulations which require Enterprise Products Partners to submit financial information on increasingly accelerated time frames. Such estimates are necessary due to the timing of compiling actual billing information and receiving third-party data needed to record transactions for financial reporting purposes. One example of such use of estimates is the accrual of an estimate of revenue and the cost of natural gas for a given month (prior to receiving actual customer and vendor- related information for the subject period). This accrual reverses in the following month and is offset by the corresponding actual customer billing and vendor-invoiced amounts. Accordingly, there is one month of estimated data in Enterprise Products Partners’ results of operations. Such estimates are generally based on actual volume and price data through the first part of the month and then extrapolated to the end of the month, adjusted accordingly for any known or expected changes in volumes or rates through the end of the month. If the basis of Enterprise Products Partners’ estimates proves incorrect, it could result in material adjustments in results of operations between periods.

 

Reserves for environmental matters

 

Each of Enterprise Products Partners’ business segments is subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations are applicable to each segment and require Enterprise Products Partners to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. Enterprise Products Partners currently has a reserve for environmental matters related to remediation costs expected to be incurred over time associated with mercury meters. It assumed this liability in connection with the GulfTerra merger. New environmental developments, such as increasingly strict environmental laws and regulations and new claims for damages to property, employees, other persons and the environment resulting from current or past operations, could result in substantial cost and future liabilities. Enterprise Products Partners accrued reserves for environmental matters when its assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Enterprise Products Partners’ assessments are based on studies, as well as site surveys, to determine the extent of any environmental damage and the necessary requirements to remediate this damage. Enterprise Products Partners’ actual results may differ from its estimates, and its estimates can be, and often are, revised in the future, either negatively or positively, depending upon the outcome or expectations based on the facts surrounding each exposure.

 

At March 31, 2005 and December 31, 2004, Enterprise Products Partners had a liability for environmental remediation of $21 million, which was derived from a range of reasonable estimates based upon studies and site surveys. In accordance with SFAS No. 5 “ Accounting for Contingencies ” and FASB Interpretation No. 14, “ Reasonable Estimation of the Amount of a Loss ,” Enterprise Products Partners recorded its best estimate of the loss.

 

Natural gas imbalances

 

Natural gas imbalances result when a customer delivers more or less gas into its pipelines than they take out. Enterprise Products Partners generally values its imbalances using a twelve-month moving average of natural gas prices, which Enterprise Products Partners believes is an appropriate assumption to estimate the value of the

 

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imbalances at the time of settlement given that the actual settlement dates are generally not known. Changes in natural gas prices may impact its estimates. Prior to the GulfTerra merger, natural gas imbalances were not significant.

 

At March 31, 2005 and December 31, 2004, its imbalance receivables were $38.5 million and $56.7 million, respectively, and are reflected as a component of accounts receivable. At March 31, 2005 and December 31, 2004, its imbalance payables were $43.9 million and $59 million, respectively, and are reflected as a component of accrued gas payables.

 

Enterprise Products Partners’ Related Party Transactions

 

The following information highlights Enterprise Products Partners’ relationships with EPCO, Shell and Enterprise Products Partners’ unconsolidated affiliates. For additional information regarding Enterprise Products Partners’ relationships with these entities, as well as our relationship with EPCO and Enterprise Products Partners, please read “Certain Relationships and Related Party Transactions.”

 

Relationship with EPCO

 

Enterprise Products Partners has an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is also a director and Chairman of Enterprise Products GP. In addition, the executive and other officers of Enterprise Products GP are employees of EPCO, including Robert G. Phillips who is Chief Executive Officer and a director of Enterprise Products GP. For a listing of Enterprise Products Partners’ directors and executive officers, please read “Management—Enterprise Products Partners.”

 

Mr. Duncan owns 50.4% of the voting stock of EPCO. The remaining shares of EPCO capital stock are held primarily by trusts for the benefit of members of Mr. Duncan’s family. In addition, at December 31, 2004, EPCO and Dan Duncan LLC, together, owned 90.1% of the membership interests of Enterprise Products GP, which in turn owns a 2% general partner interest in Enterprise Products Partners. In January 2005, an affiliate of EPCO acquired El Paso’s 9.9% membership interest in Enterprise Products GP. As a result of this transaction, EPCO and its affiliates owned 100% of Enterprise Products GP. For additional information regarding this transaction, please read Note 20 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

In addition, trust affiliates of EPCO (the 1998 Trust and 2000 Trust), owned 11,387,615 of Enterprise Products Partners’ common units at March 31, 2005. Collectively, Mr. Duncan, through his beneficial ownership of Enterprise Products Partners’ common units held personally, by the 1998 and 2000 Trusts and through subsidiaries of EPCO, controlled approximately 38.6% of its common units at March 31, 2005. For additional information regarding the beneficial ownership of Enterprise Products Partners’ common units, please read “Security Ownership of Certain Beneficial Owners and Management.”

 

The principal business activity of Enterprise Products GP is to act as the managing partner of Enterprise Products Partners. Enterprise Products Partners has no employees. All of its management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement. Enterprise Products Partners reimburses EPCO for the costs associated with employees who work on its behalf. Enterprise Products Partners has entered into an agreement with EPCO to provide trucking services to Enterprise Products Partners for the transportation of NGLs and other products. In addition, Enterprise Products Partners sells NGL products to EPCO’s Canadian affiliate. For the three months ended March 31, 2005, Enterprise Products Partners’ related party revenues from EPCO were $0.3 million and its related party expenses with EPCO were $66.3 million. During 2004, Enterprise Products Partners’ related party revenues from EPCO were $2.7 million and its related party expenses with EPCO were $230.7 million.

 

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Relationship with TEPPCO

 

On February 24, 2005, an affiliate of EPCO acquired TEPPCO GP, the general partner of TEPPCO, and 2,500,000 common units of TEPPCO from Duke Energy for approximately $1.2 billion in cash. TEPPCO GP owns a 2% general partner interest in TEPPCO and is the managing partner of TEPPCO and its subsidiaries. Subsequently, EPCO reconstituted the board of directors of TEPPCO GP, and Dr. Ralph Cunningham (a former independent director of Enterprise Products GP) was named Chairman of TEPPCO GP, and Lee W. Marshall, Sr. (a former independent director of Enterprise Products GP) was also elected a director of TEPPCO GP. Due to EPCO’s actions to reconstitute the board of directors of TEPPCO GP and TEPPCO GP’s ability to direct the management of TEPPCO, TEPPCO GP and TEPPCO became related parties to EPCO and Enterprise Products Partners during the first quarter of 2005.

 

On March 11, 2005, the Bureau of Competition of the FTC delivered written notice to EPCO’s legal advisor that it was conducting a non-public investigation to determine whether EPCO’s acquisition of TEPPCO GP may tend substantially to lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with EPCO’s purchase of TEPPCO GP. EPCO and its affiliates, including Enterprise Products Partners, may receive similar inquiries from other regulatory authorities and intend to cooperate fully with any such investigations and inquiries. In response to such FTC investigation or any inquiries EPCO and its affiliates may receive from other regulatory authorities, Enterprise Products Partners may be required to divest certain assets. In the event Enterprise Products Partners is required to divest significant assets, its financial condition could be affected.

 

Enterprise Products Partners did not have any related party revenues from TEPPCO and affiliates for the three months ended March 31, 2005. Enterprise Products Partners related party expenses paid to TEPPCO and affiliates were $1.5 million for the three months ended March 31, 2005.

 

Historical relationship with Shell

 

Historically, Shell was considered a related party because it owned more than 10% of Enterprise Products Partners’ limited partner interests and, prior to September 2003, it owned a 30% ownership interest in Enterprise Products GP. As a result of Shell selling a portion of its limited partner interests in Enterprise Products Partners to a third party in December 2004 and March 2005, Shell now owns less than 10% of its common units. Shell sold its 30% interest in Enterprise Products GP to an affiliate of EPCO in September 2003. As a result of Shell’s reduced equity interest and lack of control of Enterprise Products Partners, Shell ceased to be considered a related party beginning in the first quarter of 2005. During 2004, Enterprise Products Partners’ related party revenues from Shell were $542.9 million and its related party expenses with Shell were $725.4 million.

 

Relationships with unconsolidated affiliates

 

Enterprise Products Partners’ investment in unconsolidated affiliates with industry partners is a vital component of its business strategy. These investments are a means by which Enterprise Products Partners conducts its operations to align its interests with a supplier of raw materials or a consumer of finished products. This method of operation also enables Enterprise Products Partners to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what it could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to its other business operations. For the three months ended March 31, 2005, related party revenues for its unconsolidated affiliates were $57.9 million and related party expenses with its unconsolidated affiliates were $6.6 million. During 2004, related party revenues from its unconsolidated affiliates were $258.5 million and related party expenses with the unconsolidated affiliates were $37.6 million.

 

On occasion, Enterprise Products Partners enters into management agreements with some of its unconsolidated affiliates under which its unconsolidated affiliates pay Enterprise Products Partners management fees for the operation and management of their assets. However, these fees are not material to Enterprise

 

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Products Partners’ consolidated results of operations. Additionally, on occasion Enterprise Products Partners pays for construction costs on behalf of its unconsolidated affiliates during the initial construction phase of their assets, and these amounts are settled by direct reimbursements for the amounts Enterprise Products Partners is owed from its unconsolidated affiliates.

 

Other Items

 

Non-GAAP reconciliation . A reconciliation of Enterprise Products Partners’ measurement of total non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles follows:

 

     Year Ended December 31,

    For the Three Months
Ended March 31,


 
     2004

    2003

    2002

    2005

    2004

 
     (In thousands)  

Total non-GAAP gross operating margin

   $ 655,191     $ 410,415     $ 332,349     $ 275,214     $ 131,141  

Adjustments to reconcile total non-GAAP gross operating margin to GAAP operating income

                                        

Depreciation and amortization in operating costs and expenses

     (193,734 )     (115,643 )     (86,028 )     (99,965 )     (30,520 )

Retained lease expense, net in operating costs and expenses

     (7,705 )     (9,094 )     (9,125 )     (528 )     (2,274 )

Gain (loss) on sale of assets in operating costs and expenses

     15,901       16       1       5,436       (98 )

Selling, general and administrative costs

     (46,659 )     (37,590 )     (42,890 )     (14,693 )     (9,466 )
    


 


 


 


 


GAAP consolidated operating income

     422,994       248,104       194,307       165,464       88,783  

Other expense

     (153,625 )     (134,406 )     (94,226 )     (52,494 )     (32,457 )
    


 


 


 


 


GAAP income before provision for income taxes, minority interest and cumulative effect of changes in accounting principles

   $ 269,369     $ 113,698     $ 100,081     $ 112,970     $ 56,326  
    


 


 


 


 


 

EPCO subleases to Enterprise Products Partners certain equipment located at its Mont Belvieu facility and 100 railcars for $1 per year. These subleases (the “retained lease expense” in the previous table) are part of the administrative services agreement that Enterprise Products Partners executed with EPCO in connection with its formation in 1998. EPCO holds these items pursuant to operating leases for which it has retained the corresponding cash lease payment obligation.

 

Operating costs and expenses treat the lease payments being made by EPCO as a non-cash related party operating expense, with the offset to Partners’ Equity on the Consolidated Balance Sheets recorded as a general contribution to Enterprise Products Partners. Apart from the partnership interests Enterprise Products Partners granted to EPCO at its formation, EPCO does not receive any additional ownership rights as a result of its contribution to Enterprise Products Partners of the retained leases. For additional information regarding the EPCO administrative services agreement and the retained leases, please read “Certain Relationships and Related Party Transactions.”

 

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Cumulative effect of changes in accounting principles . As shown on Enterprise Products Partners’ Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2004, the cumulative effect of changes in accounting principles represents the combined impact of (1) changing the method its BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method and (2) changing the method in which Enterprise Products Partners accounts for its investment in VESCO from the cost method to the equity method.

 

Enterprise Products Partners’ BEF subsidiary owns an octane additive production facility that undergoes periodic planned outages of 30 to 45 days for major maintenance work. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services, and other related items. BEF used the accrue-in-advance method to record cost estimates for such activities; whereas, Enterprise Products Partners’ other operations used the expense-as-incurred method for their planned major maintenance activities. Enterprise Products Partners’ BEF subsidiary changed its accounting method on January 1, 2004 to conform to its accounting for planned major maintenance costs, which better reflects expenses in the period incurred. As such, Enterprise Products Partners believes the change is to a method that is preferable in the circumstances. The cumulative effect of this accounting change for years prior to 2004 resulted in a benefit of $7 million ($6.9 million recorded as a reduction to minority interest expense).

 

EITF 03-16, “ Accounting for Investments in Limited Liability Companies ,” requires that investments in limited liability companies that have separate ownership accounts for each investor be accounted for similar to limited partnerships under SOP No. 78-9, “Accounting for Investments in Real Estate Ventures.” Under this new guidance (applicable for the period beginning July 1, 2004), investors are required to apply the equity method of accounting to their investments at a much lower ownership threshold (typically any ownership interest greater than 3-5%) than the traditional 20% threshold applied under APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”

 

Prior to July 1, 2004, Enterprise Products Partners accounted for its 13.1% investment in VESCO using the cost method. As a result, Enterprise Products Partners recognized dividend income from VESCO to the extent that it received cash distributions from them. In accordance with the new accounting guidance in EITF 03-16, Enterprise Products Partners recorded a cumulative effect adjustment equal to the difference between (i) equity earnings from VESCO that would have been recorded using the equity method in periods prior to July 1, 2004 and (ii) the dividend income from VESCO Enterprise Products Partners recorded using the cost method in prior periods. The cumulative effect of this accounting change resulted in a benefit of $3.8 million ($3.7 million recorded as a reduction to minority interest expense).

 

Certain reclassifications have been made to Enterprise Products Partners’ first quarter 2004 financial statements to conform to the current year presentation. In accordance with SFAS No. 3, “ Reporting Accounting Changes in Interim Financial Statements ,” Enterprise Products Partners’ has reclassified amounts related to its adoption of EITF 03-16 on July 1, 2004. Enterprise Products Partners’ adoption of EITF 03-16 on that date required it to change its method of accounting for its 13.1% investment in VESCO to the equity method from the cost method. Since this change in accounting principle was made during the third quarter of 2004, Enterprise Products Partners’ statement of consolidated operations and statement of consolidated cash flows for the first quarter of 2004 has been recast for comparability purposes.

 

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For the periods indicated, the following table shows Enterprise Products Partners’ pro forma net income and earnings per unit amounts assuming the accounting changes noted above were applied retroactively to January 1, 2002.

 

     For the Year Ended December 31,

 
     2004

    2003

    2002

 
     (In thousands)  

Pro Forma income statement amounts:

                        

Historical net income

   $ 268,261     $ 104,546     $ 95,500  

Adjustments to derive pro forma net income:

                        

Effect of change from the accrue-in-advance method to the expense-as-incurred method for BEF major maintenance costs:

                        

Remove historical equity in income (losses) recorded for BEF

             31,508       (8,569 )

Record equity in (income) losses from BEF calculated using new method of accounting for major maintenance costs

             (31,800 )     8,980  

Remove cumulative effect of change in accounting principle recorded on January 1, 2004

     (7,013 )                

Remove minority interest expense associated with change in accounting principle – Sun 33.33% portion

     2,338                  

Effect of changing from the cost method to the equity method with respect to its investment in VESCO:

                        

Remove cumulative effect of change in accounting principle recorded on July 1, 2004

     (3,768 )                

Remove historical dividend income recorded from VESCO

     (2,136 )     (5,595 )     (4,737 )

Record equity earnings from VESCO

     2,429       5,133       12,303  
    


 


 


Pro forma net income

     260,111       103,792       103,477  

Enterprise Products GP interest

     (36,945 )     (20,708 )     (10,743 )
    


 


 


Pro forma net income available to limited partners

   $ 223,166     $ 83,084     $ 92,734  
    


 


 


Pro forma per unit data (basic):

                        

Historical units outstanding

     265,511       199,915       155,454  

Per unit data:

                        

As reported

   $ 0.87     $ 0.42     $ 0.55  

Pro forma

   $ 0.84     $ 0.42     $ 0.60  

Pro forma per unit data (diluted):

                        

Historical units outstanding

     266,045       206,367       176,490  

Per unit data:

                        

As reported

   $ 0.87     $ 0.41     $ 0.48  

Pro forma

   $ 0.84     $ 0.40     $ 0.53  

 

Quantitative and Qualitative Disclosures about Market Risk

 

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

 

Enterprise Products Partners recognizes financial instruments as assets and liabilities on its Consolidated Balance Sheets based on fair value. Fair value is generally defined as the amount at which a financial instrument

 

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could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of its financial instruments have been determined using available market information and appropriate valuation techniques. Enterprise Products Partners must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, its fair value estimates are not necessarily indicative of the amounts that it could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on Enterprise Products Partners’ estimates of fair value.

 

Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings.

 

To qualify as a hedge, the item to be hedged must be exposed to commodity or interest rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS No. 133, “ Accounting for Derivative Instruments and Hedging Activities ” (as amended and interpreted). Enterprise Products Partners must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge is recorded in current earnings.

 

Due to the complexity of SFAS No. 133 (as amended and interpreted), the FASB is continuing to provide guidance regarding the implementation of this accounting standard. Since this guidance is still continuing, its conclusions about the application of SFAS No. 133 may be altered, which may result in adjustments being recorded in future periods as Enterprise Products Partners adopts new FASB interpretations of this standard.

 

Interest rate risk hedging program

 

Enterprise Products Partners’ interest rate exposure results from variable and fixed rate borrowings under debt agreements. Enterprise Products Partners assesses the cash flow risk related to interest rates by identifying and measuring changes in its interest rate exposures that may impact future cash flows and evaluating hedging opportunities to manage these risks. Enterprise Products Partners uses analytical techniques to measure its exposure to fluctuations in interest rates, including cash flow sensitivity analysis models to forecast the expected impact of changes in interest rates on its future cash flows. Enterprise Products GP oversees the strategies associated with these financial risks and approves instruments that are appropriate for its requirements. The effect of a hypothetical 10% increase or decrease in variable interest rates on Enterprise Products Partners’ outstanding variable-rate debt at December 31, 2004 would yield an immaterial change in estimated annual interest expense.

 

Enterprise Products Partners manages a portion of its interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow Enterprise Products Partners to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. Enterprise Products Partners believes that it is prudent for us to maintain an appropriate balance of variable rate and fixed rate debt in the current business climate.

 

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Fair value hedges—Interest rate swaps . In January 2004, Enterprise Products Partners entered into three interest rate swap agreements with an aggregate notional amount of $250 million in which the Operating Partnership exchanged the payment of fixed rate interest on a portion of principal outstanding under Senior Notes B and C for variable rate interest. During the fourth quarter of 2004, Enterprise Products Partners entered into six additional interest rate swap agreements with an aggregate notional amount of $600 million related to a portion of the principal outstanding under Senior Notes G issued on October 4, 2004.

 

Hedged Fixed Rate Debt


   Number
of Swaps


   Period Covered by Swap

   Termination
Date of Swap


  

Fixed to Variable
Rate(1)


   Notional
Amount


Senior Notes B, 7.50% fixed rate, due February 2011

   1    January 2004 to
February 2011
   February
2011
   7.50% to 6.3%    $ 50 million

Senior Notes C, 6.375% fixed rate, due February 2013

   2    January 2004 to
February 2013
   February
2013
   6.375% to 4.9%    $ 200 million

Senior Notes G, 5.6% fixed rate, due October 2014

   6    4th Quarter 2004 to
October 2014
   October
2014
   5.6% to 3.4%    $ 600 million

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

 

Enterprise Products Partners has designated these nine interest rate swaps as fair value hedges under SFAS No. 133 since they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense.

 

These nine agreements have a combined notional amount of $850 million and match the maturity dates of the underlying debt being hedged. Under each swap agreement, Enterprise Products Partners pays the counterparty a variable interest rate based on six-month LIBOR rates (plus an applicable margin as defined in each swap agreement) and receive back from the counterparty a fixed interest rate payment based on the stated interest rate of the debt being hedged, with both payments calculated using the notional amounts stated in each swap agreement. Enterprise Products Partners settles amounts receivable from or payable to the counterparties every six months. The settlement amount is amortized ratably to earnings as either an increase or a decrease in interest expense over the six-month settlement period.

 

Total fair value of the interest rate swaps at March 31, 2005 was a liability of $18.7 million, with an offsetting decrease in the fair value of the underlying debt. Total fair value of the interest rate swaps in effect at December 31, 2004 was a receivable of approximately $0.5 million with an offsetting increase in fair value of the underlying debt. Interest expense for the three months ended March 31, 2005 reflects a benefit of $4.6 million from interest rate swap agreements. Interest expense for the year ended December 31, 2004 reflects a $9.1 million benefit from these swap agreements.

 

The following tables show the effect of hypothetical price movements on the estimated fair value (designated below as “FV”) of its interest rate swap portfolio and the related change in fair value of the underlying debt at the dates indicated (dollars in thousands):

 

Scenario


 

Resulting
Classification


  Swap FV at
December 31,
2004


    Increase
(December)
in FV of Debt


 

FV assuming no change in underlying interest rates

  Asset (Liability)   $ 505     $ (505 )

FV assuming 10% increase in underlying interest rates

  Asset (Liability)     (31,586 )     32,091  

FV assuming 10% decrease in underlying interest rates

  Asset (Liability)     32,596       (32,091 )

Scenario


 

Resulting
Classification


  Swap FV at
April 13, 2005


    Increase
(December)
in FV of Debt


 

FV assuming no change in underlying interest rates

  Asset (Liability)   $ (10,283 )        

FV assuming 10% increase in underlying interest rates

  Asset (Liability)     (41,673 )   $ (31,390 )

FV assuming 10% decrease in underlying interest rates

  Asset (Liability)     21,107       31,390  

 

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The fair value of the interest rate swaps excludes the benefit Enterprise Products Partners has already recorded in earnings. The change in fair value between December 31, 2004 and April 13, 2005 is primarily due to an increase in market interest rates relative to the forward interest rate curve used to determine the fair value of its financial instruments. The underlying floating LIBOR forward interest rate curve used to determine the April 13, 2005 fair values ranged from approximately 2.2% to 5.5% using 6-month reset periods ranging from October 2004 to October 2014.

 

Cash flow hedges—Forward starting interest rate swaps . During the first nine months of 2004, Enterprise Products Partners entered into eight forward starting interest rate swap transactions having an aggregate notional amount of $2 billion in anticipation of its financing activities associated with closing the GulfTerra merger. Enterprise Products Partners’ purpose in entering into these transactions was to effectively hedge the underlying U.S. treasury rate related to its anticipated issuance of $2 billion in principal amount of fixed rate debt. On October 4, 2004, the Operating Partnership issued $2 billion of private debt securities under Senior Notes E, F, G and H. Each of the forward starting swaps was designated as a cash flow hedge under SFAS No. 133.

 

In April 2004, Enterprise Products Partners elected to terminate the initial four forward starting swaps in order to manage and maximize the value of the swaps and to reduce future debt service costs. As a result, it received $104.5 million in cash from the counterparties. In September 2004, Enterprise Products Partners settled the remaining four swaps resulting in an $85.1 million payment to the counterparties. The net gain of $19.4 million from these settlements will be reclassified from Accumulated Other Comprehensive Income to reduce interest expense over the life of the associated debt.

 

The following table shows the notional amount covered by each forward starting swap and the cash gain (loss) associated with each swap upon settlement (dollars in thousands):

 

Term of Anticipated Debt Offering

(or Forecasted Transaction)


   Notional Amount of
Debt Covered by
Forward Starting Swaps


   Net Cash Received Upon
Settlement of Forward
Starting Swaps


 

3-year, fixed rate debt instrument

   $ 500,000    $ 4,613  

5-year, fixed rate debt instrument

     500,000      7,213  

10-year, fixed rate debt instrument

     650,000      10,677  

30-year, fixed rate debt instrument

     350,000      (3,098 )
    

  


Total

   $ 2,000,000    $ 19,405  
    

  


 

Commodity risk hedging program

 

The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond its control. In order to manage the risks associated with natural gas and NGLs, Enterprise Products Partners may enter into commodity financial instruments. The primary purpose of its commodity risk management activities is to hedge its exposure to price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas or NGLs. The commodity financial instruments Enterprise Products Partners utilizes may be settled in cash or with another financial instrument. Historically, Enterprise Products Partners has not hedged its exposure to risks associated with petrochemical products, including MTBE.

 

Enterprise Products Partners has adopted a policy to govern its use of commodity financial instruments to manage the risks of its natural gas and NGL businesses. The objective of this policy is to assist Enterprise Products Partners in achieving its profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by Enterprise Products GP. Enterprise Products Partners 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

 

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months. Enterprise Products GP oversees the strategies associated with physical and financial risks (such as those mentioned previously), approves specific activities subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.

 

Enterprise Products Partners assesses the risk of its commodity financial instrument portfolio using a sensitivity analysis model. The sensitivity analysis performed on this portfolio measures the potential income or loss (e.g., the change in fair value of the portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at the dates noted within the table presented below. In general, the quoted market prices used in the model are from those actively quoted on commodity exchanges (i.e., NYMEX) for instruments of similar duration. In those rare instances where prices are not actively quoted, Enterprise Products Partners calculates forward price curves based on similar products which are actively quoted using regression equations with strong correlation factors.

 

The sensitivity analysis model takes into account the following primary factors and assumptions:

 

    the current quoted market price of natural gas;

 

    the current quoted market price of NGLs;

 

    changes in the composition of commodities hedged (i.e., the mix between natural gas and related NGLs);

 

    fluctuations in the overall volume of commodities hedged (for both natural gas and related NGL hedges outstanding);

 

    market interest rates, which are used in determining the present value; and

 

    a liquid market for such financial instruments.

 

An increase in fair value of the commodity financial instruments (based upon the factors and assumptions noted above) approximates the income that would be recognized if all of the commodity financial instruments were settled at the dates noted within the table. Conversely, a decrease in fair value of the commodity financial instruments would result in the recording of a loss.

 

The sensitivity analysis model does not include the impact that the same hypothetical price movement would have on the hedged commodity positions to which they relate. Therefore, the impact on the fair value of the commodity financial instruments of a change in commodity prices would be offset by a corresponding gain or loss on the hedged commodity positions, assuming:

 

    the commodity financial instruments function effectively as hedges of the underlying risk;

 

    the commodity financial instruments are not closed out in advance of their expected term; and

 

    as applicable, anticipated underlying transactions settle as expected.

 

Enterprise Products Partners routinely reviews its outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific exposure. When this occurs, Enterprise Products Partners may enter into a new commodity financial instrument to reestablish the economic hedge to which the closed instrument relates.

 

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Enterprise Products Partners had a limited number of commodity financial instruments in its portfolio at March 31, 2005 and December 31, 2004. The following tables show the effect of hypothetical price movements on the estimated fair value (designated below as “FV”) of this portfolio at the dates indicated (dollars in thousands):

 

Scenario


  

Resulting
Classification


   FV at
December 31,
2003


   FV at
December 31,
2004


   FV at
April 14,
2005


 

FV assuming no change in underlying commodity prices

   Asset (Liability)    $ 4    $ 219    $ (194 )

FV assuming 10% increase in underlying commodity prices

   Asset (Liability)      4      47      (522 )

FV assuming 10% decrease in underlying commodity prices

   Asset (Liability)      4      391      135  

 

At March 31, 2005 and December 31, 2004, its portfolio primarily consisted of a limited number of natural gas cash flow and fair value hedges. Enterprise Products Partners recorded nominal amounts of earnings for its commodity hedging activities during the three months ended March 31, 2005. Enterprise Products Partners recorded $0.4 million of income related to its commodity hedging activities during 2004 and an expense of $0.6 million during 2003 that are included in Enterprise Products GP’s operating costs and expenses in the Statements of Consolidated Operations and Comprehensive Income.

 

During 2002, Enterprise Products Partners recognized a loss of $51.3 million from its commodity hedging activities that was recorded as an increase in its operating costs and expenses. Beginning in late 2000 and extending through March 2002, a large number of its commodity hedging transactions were based on the historical relationship between natural gas and NGL prices. This type of hedging strategy utilized the forward sale of natural gas at a fixed price with the expected margin on the settlement of the position offsetting or mitigating changes in the anticipated margins on NGL marketing activities and the market values of its equity NGL production. Throughout 2001, this strategy proved very successful (as the price of natural gas declined relative to its fixed positions) and was responsible for most of the $101.3 million in commodity hedging income Enterprise Products Partners recorded during 2001.

 

In late March 2002, the effectiveness of this strategy was reduced due to an unexpected rapid increase in natural gas prices whereby the loss in the value of its fixed-price natural gas financial instruments was not offset by increased natural gas processing margins. Due to the inherent uncertainty surrounding natural gas prices at the time, Enterprise Products Partners decided that it was prudent to exit this strategy, and it did so by late April 2002. The increased ineffectiveness of this strategy is the primary reason for the $51.3 million in commodity hedging losses recorded during 2002.

 

Product purchase commitments . Enterprise Products Partners has long and short-term purchase commitments for NGLs, petrochemicals and natural gas with several suppliers. The purchase prices that Enterprise Products Partners is obligated to pay under these contracts are based on market prices at the time it takes delivery of the volumes. For additional information regarding these commitments, please read “—Capital Spending—Contractual Obligations.”

 

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Effect of financial instruments on Accumulated Other Comprehensive Income (Loss)

 

The following table summarizes the effect of its cash flow hedging financial instruments on accumulated other comprehensive income (loss) since January 1, 2002.

 

           Interest Rate Financial
Instruments


       
     Commodity
Financial
Instruments


    Treasury
Locks


    Forward-
Starting Interest
Rate Swaps


    Accumulated
Other
Comprehensive
Income (Loss)
Balance


 
     (In thousands)  

Fiscal 2002 transactions

                                

Change in fair value of treasury locks

           $ (3,560 )           $ (3,560 )
            


         


Balance, December 31, 2002

             (3,560 )             (3,560 )

Reclassification of change in fair value of treasury locks

             3,560               3,560  

Gain on settlement of treasury locks

             5,354               5,354  

Reclassification of gain on settlement of treasury locks to interest expense

             (364 )             (364 )
            


         


Balance, December 31, 2003

             4,990               4,990  

Gain on settlement of forward-starting interest rate swaps

                   $ 104,531       104,531  

Loss on settlement of forward-starting interest rate swaps

                     (85,126 )     (85,126 )

Change in fair value of commodity financial instrument

   $ 1,434                       1,434  

Reclassification of gain on settlement of treasury locks to interest expense

             (418 )             (418 )

Reclassification of gain on settlement of forward-starting swaps to interest expense

                     (857 )     (857 )
    


 


 


 


Balance, December 31, 2004

     1,434       4,572       18,548       24,554  

Change in fair value of commodity financial instrument

     (1,434 )                     (1,434 )

Reclassification of gain on settlement of treasury locks to interest expense

             (109 )             (109 )

Reclassification of gain on settlement of forward-starting swaps to interest expense

                     (886 )     (886 )
    


 


 


 


Balance, March 31, 2005

     —       $ 4,463     $ 17,662     $ 22,125  
    


 


 


 


 

During the remainder of 2005, Enterprise Products Partners will reclassify a combined $3.1 million from accumulated other comprehensive income as a reduction in interest expense from its treasury locks and forward-starting interest rate swaps. In addition, Enterprise Products Partners reclassified an approximate $1.4 million gain into income from accumulated other comprehensive income related to a commodity cash flow hedge acquired in the GulfTerra merger. This gain is primarily due to an increase in fair value from that recorded for the commodity cash flow hedge at September 30, 2004.

 

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BUSINESS OF ENTERPRISE GP HOLDINGS

 

General

 

We are the sole member of Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners L.P., a publicly traded partnership. Enterprise Products Partners is a leading North American midstream energy company providing a wide range of midstream services to producers and consumers of natural gas, natural gas liquids, or NGLs, and crude oil, and is an industry leader in the development of pipeline and other midstream assets in the continental United States and deepwater Gulf of Mexico.

 

Our assets consist of the following partnership interests in Enterprise Products Partners contributed to us by EPCO:

 

    a 100% ownership of Enterprise Products GP, which owns a 2% general partner interest in Enterprise Products Partners that entitles us to receive 2% of the cash distributed by Enterprise Products Partners;

 

    the incentive distribution rights associated with Enterprise Products Partners’ general partner interest, which entitle us to receive increasing percentages of the cash distributed by Enterprise Products Partners (up to a maximum of 25%) as Enterprise Products Partners’ per unit distribution increases; and

 

    13,454,498 common units of Enterprise Products Partners, representing an approximate 3.4% limited partner interest in Enterprise Products Partners.

 

Because the incentive distribution rights currently participate at the maximum 25% sharing level (inclusive of the 2% general partner interest and associated incentive distribution rights) in all distributions made by Enterprise Products Partners above $0.3085 per unit, future growth in distributions we receive from Enterprise Products Partners will not result from an increase in the sharing level associated with the incentive distribution rights. Please read “Enterprise Products Partners’ Cash Distribution Policy—Incentive Distributions.”

 

Enterprise Products Partners is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of its general partner. Since its initial public offering in 1998, Enterprise Products Partners has increased its quarterly distribution by approximately 87%, from $0.225 per unit, or $0.90 per unit on an annualized basis, to $0.42 per unit, or $1.68 per unit on an annualized basis. Based upon Enterprise Products Partners’ recently announced quarterly distribution of $0.42 per unit declared and payable with respect to the second quarter of 2005 and the number of its common units outstanding at July 15, 2005, we would have been entitled to receive a quarterly cash distribution of approximately $25.7 million (or approximately $102.8 million on an annualized basis), consisting of $3.3 million from Enterprise Products GP’s 2% general partner interest, $16.7 million from the associated incentive distribution rights and $5.7 million from the common units of Enterprise Products Partners that we own.

 

We intend to pay our unitholders quarterly cash distributions equal to our available cash. Available cash is defined in our partnership agreement and will initially be equal to the cash distributions we receive from Enterprise Products Partners, less reserves established by our general partner for debt service requirements, general, administrative and other expenses, future distributions and other miscellaneous uses of cash. Please read “Our Cash Distribution Policy and Restrictions on Distributions.” Based upon Enterprise Products Partners’ recently declared quarterly distribution and the anticipated level of cash reserves that the board of directors of our general partner believes is prudent for us to maintain, we expect that our initial quarterly distribution will be $0.25 per unit, or $1.00 per unit on an annualized basis.

 

 

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The graph set forth below shows the historical cash distributions declared and paid or payable during the periods shown with respect to our partnership interests in Enterprise Products Partners. From 2000 through 2004, the aggregate annual cash distributions declared and paid by Enterprise Products Partners in respect of all of its partnership interests increased 209%, from approximately $141.0 million to approximately $435.8 million. Over the same period, the aggregate annual cash distributions declared and paid by Enterprise Products Partners in respect of our partnership interests increased 258%, from $17.0 million, or 12.1% of Enterprise Products Partners’ aggregate annual distributions, to $60.8 million, or 14.0% of Enterprise Products Partners’ aggregate annual distributions. The increase in historical cash distributions on our partnership interests reflected in the graph set forth below generally resulted from the following:

 

    the increase in Enterprise Products Partners’ per unit quarterly distribution from $0.25 declared and paid in the first quarter of 2000 to $0.42 declared and payable in the third quarter of 2005; and

 

    the issuance of approximately 250 million additional units by Enterprise Products Partners during such period to finance acquisitions and capital improvements.

 

LOGO

 

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The graph set forth below shows hypothetical cash distributions payable in respect of our partnership interests in Enterprise Products Partners across an illustrative range of annualized distributions per unit made by Enterprise Products Partners. This information is based upon the following assumptions:

 

    Enterprise Products Partners’ 384,695,836 common units outstanding as of July 15, 2005; and

 

    Our ownership of (i) a 2% general partner interest in Enterprise Products Partners, (ii) the associated incentive distribution rights and (iii) 13,454,498 common units of Enterprise Products Partners.

 

The following graph illustrates the impact to us of Enterprise Products Partners raising or lowering its per unit distribution from its recently announced quarterly distribution of $0.42 per unit, or $1.68 per unit on an annualized basis. This information is presented for illustrative purposes only and is not intended to be a prediction of future performance. In addition, it does not give effect to any potential future issuances of units by Enterprise Products Partners.

 

LOGO

 

Based upon Enterprise Products Partners’ current quarterly distribution and partners’ capitalization and our anticipated expenses, we expect that our initial quarterly distribution will be $0.25 per unit, or $1.00 per unit on an annualized basis. Please read “Our Cash Distribution Policy and Restrictions on Distributions.” Enterprise Products Partners’ cash distributions to us will vary depending on several factors, including Enterprise Products Partners’ outstanding partnership interests on the record date for the distribution, the per unit distribution and our relative ownership of such partnership interests. If Enterprise Products Partners increases or decreases distributions to us, we would expect to increase or decrease distributions to our unitholders accordingly, although the timing and amount of such changes in distributions, if any, will not necessarily be comparable to the timing and amount of any changes in distributions made by Enterprise Products Partners. In addition, the level of distributions we receive may be affected by the various risks associated with an investment in us and the underlying business of Enterprise Products Partners. Please read “Risk Factors.”

 

On or about November 18, 2005, we will pay a prorated quarterly distribution (based on our initial quarterly distribution of $0.25 per unit) for the period between the consummation of our initial public offering and September 30, 2005. However, we cannot assure you that any distributions will be declared or paid. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

 

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Our Business Strategy

 

Our primary objective is to increase our cash available for distributions to our unitholders and, accordingly, the value of the limited partner interests in our partnership. In recent years, major independent oil and gas and other energy companies have divested significant midstream and pipeline assets. Additionally, there have been several transactions involving the sale of general partner interests in publicly traded partnerships. We believe that the trend of asset rationalization among energy companies and transactions involving the sale of such general partner interests will continue. Our business strategy to capitalize on this trend is to:

 

    manage Enterprise Products Partners for the successful execution of its business strategy;

 

    pursue acquisitions of assets and businesses that may or may not be related to Enterprise Products Partners’ business, in accordance with our business opportunity agreements; and

 

    acquire general partner interests and associated incentive distribution rights and limited partner interests in other publicly traded partnerships.

 

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

 

How Our Partnership Agreement Terms Differ from those of Other Publicly Traded Partnerships

 

Although we are organized as a limited partnership, the terms of our partnership agreement differ from those of many other publicly traded partnerships. For example,

 

    our general partner is not entitled to incentive distributions (most publicly traded partnerships have incentive distribution rights which entitle the general partner to receive increasing percentages, commonly up to 50%, of the cash distributed in excess of a certain per unit distribution);

 

    we do not have subordinated units (most publicly traded partnerships initially have subordinated units which (i) do not receive distributions until all common units receive the minimum quarterly distribution plus arrearages and (ii) convert to common units upon meeting certain financial tests); and

 

    our general partner’s 0.01% general partner interest is fixed without any required capital contribution to us in connection with additional issuances of units by us (most general partners of publicly traded partnerships have a 1% or 2% general partner interest and are required to make additional capital contributions to the partnership in order to maintain their percentage general partner interest upon issuance of additional partnership interests by the partnership). To the extent that our general partner does not make additional capital contributions to us when we issue additional units, its general partner interest in us will not be diluted.

 

You should read the summaries in “Description of Our Units” and “Description of Our Partnership Agreement,” as well as Appendix A—Form of Amended and Restated Agreement of Limited Partnership of Enterprise GP Holdings L.P., for a more complete description of the terms of our partnership agreement.

 

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BUSINESS OF ENTERPRISE PRODUCTS PARTNERS

 

General

 

Enterprise Products Partners is a leading North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, NGLs and crude oil, and it is an industry leader in the development of pipeline and other midstream infrastructure in the continental United States and deepwater trend of the Gulf of Mexico. Enterprise Products Partners operates an integrated midstream asset base within the United States, which includes natural gas transportation, gathering, processing and storage; NGL fractionation (or separation), transportation, storage, and import and export terminaling; crude oil transportation and offshore production platform services. NGLs are used by the petrochemical and refining industries to produce plastics, motor gasoline and other industrial and consumer products and also are used as residential, agricultural and industrial fuels.

 

For the year ended December 31, 2004, Enterprise Products Partners had revenues of approximately $8.3 billion, operating income of approximately $423.0 million and net income of approximately $268.3 million.

 

Enterprise Products Partners was formed as a limited partnership in 1998 (NYSE: “EPD”) to own and operate certain NGL related businesses of EPCO. Enterprise Products Partners conducts substantially all of its business through its wholly owned Operating Partnership and its subsidiaries and joint ventures. Enterprise Products Partners is owned 98% by its limited partners and 2% by its general partner, Enterprise Products GP. Enterprise Products Partners and Enterprise Products GP are affiliates of EPCO.

 

Enterprise Products Partners does not have any employees. All of its management, administrative and operating functions are performed by employees of EPCO, pursuant to an administrative services agreement. For a discussion of the administrative services agreement, please read “Certain Relationships and Related Party Transactions.”

 

Business Strategy

 

Enterprise Products Partners’ business strategy is to:

 

    capitalize on expected increases in natural gas, NGL and crude oil production resulting from development activities in the deepwater and continental shelf areas of the Gulf of Mexico and in the Rocky Mountain region;

 

    maintain a balanced and diversified portfolio of midstream energy assets and expand this asset base through organic development projects and accretive acquisitions of complementary midstream energy assets;

 

    share capital costs and risks through joint ventures or alliances with strategic partners that will provide the raw materials for these projects or purchase the project’s end products; and

 

    increase fee-based cash flows by investing in pipelines and other fee-based businesses and de-emphasize commodity-based activities.

 

Enterprise Products Partners’ Operations

 

As a result of the GulfTerra merger, Enterprise Products Partners has reorganized its business activities into four reportable business segments: (i) Offshore Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) NGL Pipelines & Services; and (iv) Petrochemical Services. Enterprise Products Partners’ business segments are generally organized and managed according to the type of services rendered and products produced and sold. Each of these segments is more fully discussed in the following sections.

 

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Business segments are components of a business about which separate financial information is available. These components are regularly evaluated by the President and Chief Executive Officer of Enterprise Products GP in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments.

 

Enterprise Products Partners has revised its prior segment information in order to conform to the current business segment operations and presentation. For additional information regarding its business segments including revenues, gross operating margin (a non-GAAP financial measure) and assets, please read Note 18 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Offshore Pipelines & Services

 

Enterprise Products Partners owns or has an interest in (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 800 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico, which are included in its Offshore Pipelines & Services business segment.

 

Offshore Natural Gas Pipelines

 

Enterprise Products Partners’ offshore natural gas pipeline systems provide for the gathering and transmission of natural gas from natural gas production developments located in the Gulf of Mexico, primarily offshore Louisiana and Texas. Typically, these systems receive natural gas from producers, other pipelines and shippers through system interconnects and transport the natural gas to various downstream pipelines, including major interstate transmission pipelines that access multiple markets in the eastern half of the United States. In general, its offshore natural gas pipeline transportation agreements generate revenue for these systems based on transportation fees per unit of volume (typically in MMBtus) transported. These agreements tend to be long-term in nature, often involving life-of-reserve commitments with firm and interruptible components. Enterprise Products Partners’ offshore natural gas pipeline systems do not take title to the natural gas volumes they transport; rather, the shipper retains title and the associated commodity price risk.

 

Within their market area, its offshore natural gas pipelines compete with other pipelines (both regulated and unregulated systems) primarily on the basis of price (in terms of transportation fees) and connections to downstream markets. These systems exhibit little to no effects of seasonality; however, they may be affected by weather events such as hurricanes and tropical storms in the Gulf of Mexico.

 

Enterprise Products Partners’ offshore natural gas pipeline business is affected by natural gas exploration and production activities in these operating areas. If these exploration and production activities decline due to (i) the inability of producers to find economically viable reserves; (ii) a weakened domestic economy which lowers natural gas demand; or (iii) natural depletion of the gas production fields to which its natural gas pipelines are connected, then throughput volumes on these pipelines will decline, thereby affecting its earnings from these assets. Enterprise Products Partners actively seeks to offset the loss of volumes due to natural depletion by adding connections to new customers and gas production fields. In addition, Enterprise Products Partners believes its offshore natural gas pipeline systems are positioned to benefit from expected increases in natural gas production from new deepwater developments in the Gulf of Mexico.

 

Enterprise Products Partners’ offshore natural gas pipeline systems are subject to various types of regulation. For a discussion of the general impact of governmental regulation on Enterprise Products Partners’ business, please read “—Regulation and Environmental Matters.”

 

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The following table summarizes Enterprise Products Partners’ primary offshore natural gas pipeline assets at March 1, 2005. Enterprise Products Partners’ ownership interest in each pipeline is held either through a consolidated subsidiary or indirectly through a company in which Enterprise Products Partners has an investment accounted for under the equity method. For additional information regarding Enterprise Products Partners’ equity method investments, please read Note 7 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Offshore Natural Gas Pipelines


   Length
(Miles)


   Enterprise
Products
Partners’
Ownership
Interest


   

Manta Ray Gathering System

   235    25.7%    

High Island Offshore System(1)

   204    100%    

Viosca Knoll Gathering System(1)

   162    100%    

Green Canyon Laterals(1)

   136    Various   (2)

Anaconda Gathering System(1)

   110    100%    

Nautilus System

   101    25.7%    

East Breaks System(1)

   85    100%    

Phoenix Gathering System(1)

   78    100%    

Nemo Gathering System

   24    33.9%    

Falcon Gas Pipeline(1)

   14    100%    
    
        

Total offshore natural gas pipelines

   1,149         
    
        

(1) Acquired as a result of the GulfTerra merger on September 30, 2004.
(2) Enterprise Products Partners’ ownership interest in the Green Canyon Laterals ranges from 2.7% to 100%.

 

The 1,149 miles of offshore natural gas pipelines shown in the preceding table excludes the Stingray and Triton natural gas pipelines owned by Starfish. In connection with the GulfTerra merger, Enterprise Products Partners is required under a consent decree to sell its 50% interest in Starfish. In January 2005, Enterprise Products Partners entered into a contract with a third party to sell this investment for approximately $42.1 million. Enterprise Products Partners expects to close this sale during the first quarter of 2005. The sale requires FTC approval under the terms of the consent decree relating to the GulfTerra merger and is subject to other customary closing conditions.

 

The following table shows the approximate capacity (on a net basis in accordance with its ownership interest) of each of its primary offshore natural gas pipeline systems and an estimate of capacity utilization for the periods in which Enterprise Products Partners owned these assets.

 

Offshore Natural Gas Pipelines


  

Approximate
Net Capacity

(MMcf/d)


   Estimated Average Utilization Rate(1)

 
          2004    

        2003    

        2002    

 

High Island Offshore System

   1,800    40 %(2)            

Viosca Knoll Gathering System

   1,160    18 %(2)            

Green Canyon Laterals

   649    9 %(2)            

Anaconda Gas Pipeline

   400    21 %(2)            

East Breaks System

   400    54 %(2)            

Phoenix Gathering System

   450    27 %(2)            

Falcon Gas Pipeline

   400    49 %(2)            

Other Gulf of Mexico Pipelines(3)

   1,022    41 %   41 %   48 %

(1) The estimated average utilization rate for each asset is based on a conversion factor where approximately 1,020 Btus of natural gas is equivalent to 1 cubic foot of natural gas.

 

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(2) Utilization rates are for the three months that Enterprise Products Partners owned these assets during 2004 (October through December). Enterprise Products Partners acquired these assets as a result of the GulfTerra merger.
(3) The approximate capacity shown for these pipelines includes 560 MMcf/d of net capacity for the Stingray pipeline, which is expected to be disposed of during the first quarter of 2005. This category also includes the approximate net throughput capacities of its Nautilus (154 MMcf/d), Manta Ray (206 MMcf/d) and Nemo (102 MMcf/d) natural gas gathering pipelines.

 

The following table reflects overall throughput rates of its offshore natural gas pipelines (on a net basis in accordance with its ownership interests) for the periods in which Enterprise Products Partners owned them during 2004, 2003 and 2002. The throughput rate for 2004 increased as a result of offshore natural gas pipeline assets acquired in the GulfTerra merger on September 30, 2004.

 

     For the Year Ended December 31,

         2004    

       2003    

       2002    

Offshore natural gas pipeline throughput volume, net (BBtus/d)

   2,081    433    500

 

The following is a brief description of each of its primary offshore natural gas pipeline assets, all of which Enterprise Products Partners operates with the exception of the Manta Ray Gathering System, Nautilus System, Nemo Gathering System and certain components of the Green Canyon Laterals:

 

Manta Ray Gathering System . The Manta Ray Gathering System consists of natural gas gathering pipelines and related equipment located in the Gulf of Mexico offshore Louisiana. The primary sources of throughput for the Manta Ray system are the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico to numerous downstream pipelines, including its Nautilus pipeline.

 

High Island Offshore System . HIOS is an offshore natural gas transmission system that transports natural gas from producing fields located in the Galveston, Garden Banks, West Cameron, High Island, and East Breaks areas of the Gulf of Mexico to the ANR and Tennessee Gas Pipeline and the U-T Offshore System.

 

Viosca Knoll Gathering System . The Viosca Knoll Gathering System is a natural gas gathering system located off the coast of Louisiana that transports natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico to several major interstate pipelines, including the Tennessee Gas Pipeline, Columbia Gulf, Southern Natural, Transco and Destin pipelines.

 

Green Canyon Laterals . The Green Canyon Laterals consist of 28 laterals, which are extensions of natural gas pipelines, located in the Gulf of Mexico offshore Texas and Louisiana. These laterals deliver natural gas to numerous downstream pipelines, including HIOS.

 

Anaconda Gathering System . The Anaconda Gathering System is a natural gas gathering system that connects its Marco Polo tension-leg platform and ChevronTexaco and BHP’s Typhoon platform, both of which are located in the Green Canyon area of the Gulf of Mexico, to the ANR pipeline system.

 

Nautilus System . The Nautilus System consists of a natural gas pipeline system located in the Gulf of Mexico offshore Louisiana. Currently, the primary source of natural gas throughput for the Nautilus system is volume originating from Enterprise Products Partners’ Manta Ray system. Natural gas volumes transported by the Nautilus system are delivered to its Neptune gas plant for processing.

 

East Breaks System . The East Breaks System is a natural gas gathering system that connects the Hoover-Diana deepwater platform, which is owned by affiliates of ExxonMobil and BP and located in Alaminos Canyon Block 25, to HIOS.

 

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Phoenix Gathering System . The Phoenix Gathering System is a natural gas gathering system, which commenced operations in July 2004, connecting Kerr-McGee and Devon’s Red Hawk platform located in the Garden Banks area of the Gulf of Mexico to the ANR pipeline system.

 

Nemo Gathering System . The Nemo Gathering System is a natural gas gathering pipeline located offshore Louisiana that transports natural gas volumes from Shell’s Green Canyon developments to an interconnect with its Manta Ray Gathering System.

 

Falcon Gas Pipeline . The Falcon Gas Pipeline is a natural gas pipeline located off the Texas coast that delivers Pioneer Natural Resources’ natural gas processed at its Falcon Nest platform to a connection with the Central Texas Gathering System located on the Brazos Addition Block 133 platform.

 

Offshore Crude Oil Pipelines

 

As a result of the GulfTerra merger, Enterprise Products Partners acquired interests in several offshore crude oil pipeline systems which are located in the vicinity of oil-producing areas in the Gulf of Mexico. Typically, these systems receive oil from offshore production developments, other pipelines or shippers through system interconnects and deliver the oil to either onshore locations or to other offshore interconnecting pipelines. In general, Enterprise Products Partners’ oil pipeline systems generate revenue based on agreements resulting from purchasing and selling products at price differentials per unit of volume (typically in barrels) received. A substantial portion of the revenues generated by Enterprise Products Partners’ oil pipeline systems are attributed to production from reserves committed under long-term contracts for the productive life of the relevant field or purchases and sales of crude oil with terms from two to twelve months. The rates Enterprise Products Partners charges for its services are dependent on the volume of crude oil to be delivered and the amount and term of the reserve commitment by the customer.

 

Cameron Highway’s, Poseidon’s and Typhoon’s agreements require the purchase of producer’s oil at the inlet of their pipelines for an index-based price, less a price differential. At the outlet of their pipelines, Cameron Highway, Poseidon and Typhoon sell the oil back to producers at the same index-based price. These transactions are recorded as net revenue.

 

Enterprise Products Partners’ offshore oil pipeline systems were built as a result of the need for additional crude oil capacity to receive and deliver new deepwater oil production to shore. Enterprise Products Partners’ competition includes other oil pipeline systems, built, owned and operated by producers to handle their owns production and, as capacity is available, production for others. Enterprise Products Partners’ oil pipelines compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation fees and access to onshore markets. In addition, the ability of its pipelines to access future reserves will be subject to its ability, or the producer’s ability, to fund the significant capital expenditures required to connect to the new production. These pipeline systems exhibit little to no effects of seasonality; however, they may be affected by cyclical weather events such as hurricanes and tropical storms in the Gulf of Mexico.

 

Enterprise Products Partners’ offshore oil pipeline business is affected by crude oil exploration and production activities in these operating areas. If these exploration and production activities decline due to (i) the inability of producers to find economically viable reserves; (ii) a weakened domestic economy which lowers crude oil demand; or (iii) natural depletion of the crude oil production fields to which Enterprise Products Partners’ oil pipelines are connected, then throughput volumes on these pipelines will decline, thereby affecting its earnings from these assets. Enterprise Products Partners actively seeks to offset the loss of volumes due to natural depletion by adding connections to new customers and oil production fields.

 

Enterprise Products Partners’ offshore crude oil pipeline systems are subject to various types of regulation. For a discussion of the general impact of governmental regulation on its business, please read “ Regulation and Environmental Matters.”

 

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The following table summarizes its primary offshore oil pipeline assets at March 1, 2005. Enterprise Products Partners’ ownership interest in each pipeline is held either through a consolidated subsidiary or indirectly through a company in which Enterprise Products Partners has an investment accounted for under the equity method. For additional information regarding its equity method investments, please read Note 7 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Offshore Crude Oil Pipelines


  

Length

(Miles)


  

Enterprise
Products
Partners’
Ownership

Interest


 

Cameron Highway Oil Pipeline

   390    50 %

Poseidon System

   324    36 %

Allegheny Oil Pipeline

   43    100 %

Marco Polo Oil Pipeline

   36    100 %

Typhoon Oil Pipeline

   16    100 %

Tarantula Oil Pipeline

   4    100 %
    
      

Total offshore oil pipelines

   813       
    
      

 

The following table shows the approximate capacity (on a net basis in accordance with its ownership interest) of each of Enterprise Products Partners’ primary offshore crude oil pipeline systems and an estimate of capacity utilization for the three month period (October 2004 through December 2004) in which Enterprise Products Partners owned these assets.

 

Offshore Crude Oil Pipelines


   Approximate
Capacity
(MBbls/d, net)


  

Estimated
Average
Utilization

Rate


 

Poseidon System

   144    35 %

Allegheny Oil Pipeline

   135    26 %

Marco Polo Oil Pipeline

   120    19 %

Typhoon Oil Pipeline

   100    29 %

 

The following table reflects overall throughput volumes of Enterprise Products Partners’ offshore crude oil pipelines (on a net basis in accordance with its ownership interests) for the three-month period that Enterprise Products Partners owned them during 2004 (October 2004 through September 2004).

 

     2004

Offshore crude oil pipeline throughput volume, net (MBbls/d)

   138

 

The following is a brief description of each of Enterprise Products Partners’ primary offshore crude oil pipeline assets, all of which it operates:

 

Cameron Highway Oil Pipeline . The Cameron Highway Oil Pipeline, which commenced operations during the first quarter of 2005, is designed to gather production from the deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in Port Arthur and Texas City, Texas.

 

Cameron Highway is supported by life of lease dedications with BP, BHP Billiton Plc, or BHP, and Unocal Corporation for their production from the Holstein, Mad Dog and Atlantis fields and with Kerr McGee for its production from the Constitution and Ticonderoga fields. Additionally, Cameron Highway has contracted with Shell to purchase and sell its 50% share of crude oil production from the Holstein field. The Holstein field began producing in December 2004 and first production from the Mad Dog field commenced January 2005. Production from the Atlantis, Constitution and Ticonderoga fields is expected to begin in 2006.

 

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Poseidon System . The Poseidon System is a major offshore sour crude oil pipeline system that gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico to onshore locations at Houma, Louisiana. The Poseidon System includes the newly constructed Front Runner Oil Pipeline, which is a 36-mile crude oil pipeline that connects the Front Runner field located in Green Canyon Blocks 338 and 339 in the central Gulf of Mexico with Poseidon’s main pipeline at Ship Shoal Block 332. The Front Runner Oil Pipeline received its first volumes from the Front Runner field in January 2005.

 

Allegheny Oil Pipeline . The Allegheny Oil Pipeline is an offshore crude oil pipeline system that connects the Allegheny and South Timbalier 316 platforms in the Green Canyon area of the Gulf of Mexico with its Poseidon System at the Ship Shoal 332 platform. Oil production from the Allegheny and South Timbalier 316 fields is committed to the Allegheny Oil Pipeline. In addition, the Allegheny Oil Pipeline receives crude oil production gathered from Enterprise Products Partners’ Marco Polo Oil Pipeline.

 

Marco Polo Oil Pipeline . The Marco Polo Oil Pipeline is a newly constructed crude oil gathering system which gathers crude oil from Enterprise Products Partners’ Marco Polo tension-leg platform to an interconnect with its Allegheny Oil Pipeline in Green Canyon Block 164.

 

Typhoon Oil Pipeline . The Typhoon Oil Pipeline is an offshore crude oil pipeline that connects ChevronTexaco and BHP’s Typhoon platform in the Green Canyon area of the Gulf of Mexico to Shell’s Boxer platform. The Shell Boxer platform provides access to Enterprise Products Partners’ Poseidon System through a third-party pipeline.

 

Tarantula Oil Pipeline . The Tarantula Oil Pipeline is a newly constructed oil pipeline that connects the Tarantula field located in South Timbalier Block 308 in the central Gulf of Mexico to its Poseidon System. The Tarantula Oil Pipeline received its first volumes from the Tarantula field in January 2005.

 

Offshore Platforms

 

As a result of the GulfTerra merger, Enterprise Products Partners acquired ownership interests in seven multi-purpose offshore hub platforms located in the Gulf of Mexico. Offshore platforms are critical components of the offshore infrastructure in the Gulf of Mexico, supporting drilling and production operations, and therefore play a key role in the overall development of offshore oil and natural gas reserves. Platforms are used to: (i) interconnect with the offshore pipeline grid; (ii) provide an efficient means to perform pipeline maintenance (iii) locate compression, separation, production handling and other facilities; (iv) conduct drilling operations during the initial development phase of an oil and natural gas property; and (v) process off-lease production.

 

Enterprise Products Partners’ platforms generally earn revenues through demand fees and commodity charges. A demand fee is typically a fixed fee charged to a customer using its platform services regardless of the volume the customer delivers to the platform. A commodity charge is typically a fixed fee per million cubic feet of natural gas or barrel of crude oil, whichever the case may be, multiplied by the volume delivered to the platform by the customer. Contracts for platform services often include both demand fees and commodity charges, but demand fees generally expire after a contractual fixed period of time.

 

Offshore platforms are subject to similar competitive factors as Enterprise Products Partners’ offshore natural gas and oil pipeline systems. These assets generally compete with other platform service providers on the basis of proximity and access to existing reserves and pipeline systems, as well as costs and rates. Furthermore, Enterprise Products Partners’ competitors in this business may possess greater capital resources than it has. Enterprise Products Partners’ platforms exhibit little to no effects of seasonality; however, they may be affected by cyclical weather events such as hurricanes and tropical storms in the Gulf of Mexico.

 

Enterprise Products Partners’ offshore platforms are affected by crude oil and natural gas exploration and production activities in these operating areas. If these exploration and production activities decline due to (i) the

 

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inability of producers to find economically viable reserves; (ii) a weakened domestic economy which lowers crude oil and natural gas demand; or (iii) natural depletion of the oil and gas fields to which they are connected, then processing volumes on these platforms will decline, thereby affecting its earnings from these assets. Enterprise Products Partners actively seeks to offset the loss of volumes due to natural depletion by adding connections to new customers and fields.

 

Enterprise Products Partners’ offshore platforms are subject to various types of regulation. For a discussion of the general impact of governmental regulation on its business, please read “—Regulation and Environmental Matters.”

 

The following table summarizes Enterprise Products Partners’ primary offshore platform assets at March 1, 2005. Enterprise Products Partners’ ownership interest in each platform is held either through a consolidated subsidiary or indirectly through a company in which it has an investment accounted for under the equity method. For additional information regarding Enterprise Products Partners’ equity method investments, please read Note 7 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Offshore Platforms


   Water
Depth
(feet)


   Acquired or Constructed

  

Enterprise
Products
Partners’
Ownership

Interest


 

Marco Polo tension-leg platform

   4,300    Constructed    50 %

Viosca Knoll 817

   671    Constructed    100 %

Garden Banks 72

   518    Constructed    50 %

Ship Shoal 332 A and B

   438    Acquired/Constructed    50 %

East Cameron 373

   441    Constructed    100 %

Falcon Nest

   389    Constructed    100 %

Ship Shoal 331

   376    Acquired    100 %

 

The following table shows the approximate platform processing capacity (on a net basis in accordance with its ownership interest) of Enterprise Products Partners’ primary offshore platforms and an estimate of capacity utilization for the three month period (October 2004 through December 2004) in which it owned these assets. Ship Shoal 332 A and B and 331 are excluded from this table since their primary functions are to serve as junction platforms for pipeline interconnects.

 

     Approximate Capacity

   Estimated Average
Utilization Rate(1)


 

Offshore Platform


  

Natural Gas

(MMcf/d, net)


   Crude Oil
(MBbls/d, net)


   Natural Gas

    Crude Oil

 

Marco Polo tension-leg platform

   150    60    11 %   19 %

Viosca Knoll 817

   140    5    1 %   12 %

Garden Banks 72

   40    28    11 %   3 %

East Cameron 373

   190    5    45 %   10 %

Falcon Nest

   400    2    47 %   38 %

(1) The estimated average utilization rate for each asset is based on a conversion factor where approximately 1,020 Btus of natural gas is equivalent to 1 cubic foot of natural gas.

 

The following table reflects overall platform processing volumes of natural gas and crude oil of Enterprise Products Partners’ offshore platforms (on a net basis in accordance with its ownership interest) for the three-month period that it owned them during 2004 (October 2004 through December 2004).

 

     Natural Gas
(BBtus/d, net)


   Oil
(MBbls/d, net)


Offshore platform processing volumes, net

   306    14

 

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The following is a brief description of each of Enterprise Products Partners’ primary offshore platform assets, all of which it operates with the exception of the Marco Polo tension-leg platform and Ship Shoal 332 A, East Cameron 373 and Ship Shoal 331 platforms:

 

Marco Polo . The Marco Polo tension-leg platform was installed in the first quarter of 2004 and commenced operations in July 2004. The Marco Polo tension-leg platform processes crude oil and natural gas from Anadarko’s Marco Polo field located in Green Canyon Block 608. Additionally, the Marco Polo tension-leg platform is expected to begin receiving production volumes from the K2 and K2 North fields during 2005.

 

Anadarko has dedicated 69,120 acres of property to the Marco Polo tension-leg platform, including acreage underlying their Marco Polo field, for the life of the reserves. Additionally, Anadarko has contracted with the Marco Polo tension-leg platform for 100 MBbls/d of crude oil and 150 MMcf/d of firm processing capacity. The remainder of the platform’s oil processing capacity is contracted to Anadarko’s partners in the K-2 field. Enterprise Products Partners has certain rights to get capacity back to market to third parties, if it becomes available. Anadarko is operator of the Marco Polo tension-leg platform.

 

Viosca Knoll 817 . The Viosca Knoll 817 platform is centrally located on Enterprise Products Partners’ Viosca Knoll Gathering System. This platform serves as a base for gathering deepwater production in the area, including ExxonMobil’s, Shell’s, and BP’s Ram Powell development. A 7,000 horsepower compressor on the platform facilitates deliveries from Enterprise Products Partners’ Viosca Knoll Gathering System to multiple downstream interstate pipelines. The platform is also used as a base for crude oil and natural gas production from Enterprise Products Partners’ Viosca Knoll Block 817 lease and Walter Oil and Gas’ Viosca Knoll 862 lease.

 

Garden Banks 72 . The Garden Banks 72 platform serves as a base for landing deepwater production from Newfield Exploration Inc.’s Garden Banks Block 161 development, LLOG Exploration Offshore’s Garden Banks Block 378 lease and Amerada Hess Corporation’s Garden Banks Block 158 lease. The platform is also used as a junction platform for Enterprise Products Partners’ Cameron Highway Oil Pipeline.

 

Ship Shoal 332 A and B . The Ship Shoal 332A platform serves as a junction platform for Enterprise Products Partners’ Manta Ray and Nemo natural gas pipelines and its Poseidon and Allegheny oil pipelines. Enbridge operates the Ship Shoal 332A platform. The Ship Shoal 332B platform is connected to Ship Shoal 332A platform and is owned by Cameron Highway, Enterprise Products Partners’ unconsolidated affiliate. The Ship Shoal 332B platform is a major junction platform for the Cameron Highway Oil Pipeline and will also serve as the junction platform for the Constitution Oil Pipeline.

 

East Cameron 373 . The East Cameron 373 platform serves as the host for Kerr-McGee’s East Cameron Block 373 production and as the gathering site for production at Garden Banks Blocks 108, 152, 197, 200 and 201. Kerr-McGee operates the East Cameron 373 platform.

 

Falcon Nest . The Falcon Nest platform processes natural gas from Pioneer Natural Resources Company’s Falcon, Harrier and Raptor fields. Pioneer has dedicated 69,120 acres of property to this platform for the life of the reserves.

 

Ship Shoal 331 . The Ship Shoal 331 platform is used by Maritech Resources, Inc. to support production operations.

 

Major Construction Projects

 

Independence Hub Platform and Independence Trail Pipeline System . In November 2004, Enterprise Products Partners entered into an agreement with the Atwater Valley Producers Group for the dedication, processing and gathering of natural gas and condensate production from several natural gas fields in the Atwater Valley, DeSoto Canyon and Lloyd Ridge areas, which we refer to as the anchor fields, of the deepwater Gulf of

 

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Mexico. Enterprise Products Partners will design, construct, and own Independence Hub, a 105-foot deep-draft, semi-submersible platform with a two-level production deck, which will be capable of processing 850 MMcf/d of natural gas. The platform, which is estimated to cost approximately $385 million, will be operated by Anadarko, and is designed to process production from its anchor fields and has excess payload capacity to support ten additional pipeline risers. In December 2004, Enterprise Products Partners entered into an agreement with Cal Dive to sell them a 20% indirect interest in the Independence Hub platform. Under the terms of the agreement, Enterprise Products Partners will have access to Cal Dive’s fleet of vessels, which will assist it in the construction of the Independence Hub platform and the related export pipeline.

 

The Independence Hub platform will be located on Mississippi Canyon Block 920, in a water depth of 8,000 feet. This location was selected for the permanently anchored platform based on favorable seafloor conditions and proximity to the identified anchor fields. First production is expected in 2007. Under the terms of the agreement, the production fields served by the Independence Hub platform will include the nine dedicated anchor fields in addition to future discoveries on surrounding undeveloped blocks.

 

Additionally, Enterprise Products Partners will construct, own, and operate the 134-mile Independence Trail natural gas pipeline system, which will have a throughput capacity of approximately 850 MMcf/d of natural gas. The pipeline system, which is estimated to cost $280 million, will transport production from the Independence Hub platform to the Tennessee Gas Pipeline. Enterprise Products Partners entered into an agreement with Tennessee Gas Pipeline under which Tennessee Gas Pipeline will pay it $15 million for contributions in aid of construction to connect the Independence Trail natural gas pipeline system to their pipeline system. In November 2004, Tennessee Gas Pipeline reimbursed Enterprise Products Partners $7 million for construction costs incurred. The balance of $8 million would be reimbursed by Tennessee Gas Pipeline when additional costs are incurred and is contingent upon Enterprise Products Partners’ completion of the Independence Trail project, which is expected during 2006.

 

Constitution Gathering System . In July 2004, GulfTerra entered into a definitive agreement to construct, own, and operate oil and natural gas pipelines to provide production gathering services for the Constitution field, which is 100% owned by Kerr-McGee. The Constitution field is located at a depth of 5,300 feet in Green Canyon Blocks 679 and 680 in the Central Gulf of Mexico. The new $53.4 million natural gas pipeline will be a 32-mile, 16-inch pipeline with a transport capacity of up to 200 MMcf/d and will connect to its existing Anaconda Gathering System. The new $76.2 million oil pipeline will be a 70-mile, 16-inch pipeline with a minimum transport capacity of 80 MBbls/d that will connect with the Cameron Highway Oil Pipeline and Poseidon System at Enterprise Products Partners’ Ship Shoal 332B platform. These pipelines are expected to start transporting volumes scheduled in the first half of 2006.

 

Intangible Assets

 

At December 31, 2004, the Offshore Pipelines & Services segment included $200 million of intangible assets primarily related to customer relationships. For information regarding its intangible assets, please read Note 8 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Onshore Natural Gas Pipelines & Services

 

Enterprise Products Partners owns or has interests in approximately 17,200 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, Enterprise Products Partners owns two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast domestic natural gas markets. This segment also includes leased natural gas storage facilities located in Texas and Louisiana.

 

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Onshore Natural Gas Pipelines

 

Enterprise Products Partners’ onshore natural gas pipeline systems provide for the gathering and transmission of natural gas from onshore developments, such as the San Juan and Permian supply basins, or from offshore developments in the Gulf of Mexico, through connections with offshore pipelines. Typically, these systems receive natural gas from producers, other pipelines or shippers through system interconnects and redeliver the natural gas to processing facilities, local gas distribution companies, industrial customers or to other onshore pipelines. Generally, natural gas pipeline gathering or transportation agreements generate revenue for these systems based on a fee per unit of volume (generally in MMBtus) gathered or transported. Natural gas pipelines (such as its Acadian Gas and Alabama Intrastate systems) may also gather and purchase natural gas from producers and suppliers and resell such natural gas to customers such as electric utility companies, local natural gas distribution companies and industrial customers.

 

Enterprise Products Partners’ Acadian Gas and Alabama Intrastate pipelines are exposed to commodity price risk to the extent they take title to natural gas volumes through certain of their contracts. In addition, its San Juan Gathering and Permian Basin pipeline systems provide aggregating and bundling services, in which Enterprise Products Partners purchases and resells natural gas for certain small producers. Also, several of its gathering systems, while not providing marketing services, have some exposure to risks related to commodity prices through transportation arrangements with shippers. For example, over 95% of the volumes handled by the San Juan Gathering System are fee-based arrangements, 80% of which are calculated as a percentage of a regional price index for natural gas. Enterprise Products Partners uses commodity financial instruments from time to time to mitigate its exposure to risks related to commodity prices.

 

Within their market areas, its onshore natural gas pipelines compete with other onshore natural gas pipelines on the basis of price (in terms of transportation fees and/or natural gas selling prices), service and flexibility. Enterprise Products Partners’ competitive position within the onshore market is enhanced by its longstanding relationships with customers and the limited number of delivery pipelines connected (or capable of being connected) to the customers Enterprise Products Partners serves.

 

Enterprise Products Partners’ onshore natural gas pipeline business is affected by natural gas exploration and production activities. If these exploration and production activities decline due to (i) the inability of producers to find economically viable reserves; (ii) a weakened domestic economy which lowers natural gas demand; or (iii) natural depletion of the oil and gas fields to which they are connected, then throughput volumes on these pipelines will decline, thereby affecting its earnings from these assets. Enterprise Products Partners actively seeks to offset the loss of volumes due to natural depletion by adding connections to new customers and fields.

 

Certain of Enterprise Products Partners’ onshore natural gas pipelines (such as the Texas Intrastate System) are subject to regulation. For a discussion of the general impact of governmental regulation on its business, please read “ Regulation and Environmental Matters.”

 

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The following table summarizes Enterprise Products Partners’ primary onshore natural gas pipeline systems at March 1, 2005. Enterprise Products Partners’ ownership interest in each pipeline is held either through a consolidated subsidiary or indirectly through a company in which it has an investment accounted for under the equity method. For additional information regarding its equity method investments, please read Note 7 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Onshore Natural Gas Pipelines


   Length
(Miles)


   Enterprise
Products
Partners’
Ownership
Interest


 

Texas Intrastate System(1)

   8,222    100 %(2)

San Juan Gathering System(1)

   5,404    100 %

Permian Basin System(1)

   1,477    100 %

Acadian Gas System

   1,042    100 %(3)

Alabama Intrastate System(1)

   450    100 %

Delmita Gathering System(1)(4)

   295    100 %

Big Thicket Gathering System(1)(4)

   240    100 %

Indian Springs Gathering System(5)

   89    80 %
    
      

Total onshore natural gas pipelines

   17,219       
    
      

(1) These pipelines were acquired as a result of the GulfTerra merger.
(2) The Texas Intrastate system includes some pipelines in which Enterprise Products Partners owns undivided interests.
(3) Enterprise Products Partners owns 100% of 1,015 miles of the Acadian Gas System and 49.5% of the related 27-mile Evangeline gas pipeline.
(4) These gathering systems are an integral part of its natural gas processing business, the results of operations and assets of which are accounted for under its NGL Pipelines & Services business segment.
(5) Enterprise Products Partners acquired an ownership interest in this natural gas gathering system in January 2005.

 

The following table shows the approximate capacity (on a net basis in accordance with its ownership interest) of each of its primary onshore natural gas pipeline systems and an estimate of capacity utilization for the periods in which Enterprise Products Partners owned these assets. The utilization rates for the assets Enterprise Products Partners acquired in the GulfTerra merger are for the three months that it owned them during 2004 (October through December).

 

    

Approximate
Capacity
(MMcf/d, net)


  

Estimated Average(1)

For the Year Ended December 31,


 

Onshore Natural Gas Pipelines


          2004    

        2003    

        2002    

 

Texas Intrastate System

   4,975    61 %(2)            

San Juan Gathering System

   1,100    100 %(2)            

Permian Basin System

   470    72 %(2)            

Acadian Gas System

   954    66 %   61 %   72 %

Alabama Intrastate System

   200    77 %(2)            

(1) The estimated average utilization rate for each asset is based on a conversion factor where approximately 1,020 Btus of natural gas is equivalent to 1 cubic foot of natural gas.
(2) Utilization rates are for the three months that Enterprise Products Partners owned these assets during 2004 (October through December). Enterprise Products Partners acquired these assets as a result of the GulfTerra merger.

 

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The following table reflects overall throughput rates of Enterprise Products Partners’ onshore natural gas pipelines (on a net basis in accordance with its ownership interest) for the periods in which it owned them during 2004, 2003 and 2002. The throughput rate for 2004 increased as a result of onshore natural gas pipeline assets acquired in the GulfTerra merger on September 30, 2004.

 

     For the Year Ended December 31,

          2004     

        2003     

        2002     

Onshore natural gas pipeline throughput volume, net (BBtus/d)

   5,638    600    701

 

The following is a brief description of each of Enterprise Products Partners’ primary onshore natural gas pipeline assets, all of which it operates:

 

Texas Intrastate System . The Texas Intrastate System gathers and transports natural gas from supply basins in Texas and offshore in the Gulf of Mexico to local gas distribution companies and electric generation and industrial customers. This system has over 100 interconnections and serves important natural gas producing and market areas in Texas, including natural gas-fired electric plants and other key markets, such as Corpus Christi, the San Antonio/Austin area, the Beaumont/Orange area, and the large Houston Ship Channel industrial market. The Texas Intrastate System consists of the GulfTerra Texas Intrastate natural gas gathering system, the TPC Offshore natural gas gathering system and the Channel natural gas transmission pipeline.

 

The GulfTerra Texas Intrastate natural gas gathering system is one of the largest intrastate pipeline systems in the United States based on miles of pipe. This system consists of 7,292 miles of main lines, laterals and gathering lines and also includes some smaller pipelines in which Enterprise Products Partners owns undivided interests. The TPC Offshore natural gas gathering system consists of 197 miles of pipelines located in the coastal waters of south Texas. The TPC Offshore system also includes some smaller pipelines in which Enterprise Products Partners owns undivided interests. The Channel pipeline system is a 733-mile intrastate natural gas transmission system located along the Gulf Coast of Texas. Enterprise Products Partners owns a 50% undivided interest in the Channel natural gas transmission pipeline.

 

San Juan Gathering System . The San Juan Gathering System serves natural gas producers in the San Juan Basin of New Mexico and Colorado, where the system has connections to approximately 9,500 receipt points. This system gathers natural gas from wells in the San Juan Basin and delivers the natural gas to its Chaco natural gas processing facility and to Blanco natural gas processing facility owned by BP and ConocoPhillips. A project is currently underway to increase the capacity on the San Juan gathering system by 130 MMcf/d. The project was started in late 2003 and will be completed in stages through 2006.

 

Permian Basin System . The Permian Basin System gathers natural gas from numerous wells in the Permian Basin region of Texas and New Mexico and delivers the natural gas into the El Paso Corporation Natural Gas, Transwestern and Oasis pipelines. The Permian Basin System consists of the Waha Natural Gas Gathering System and Carlsbad Natural Gas Gathering System. The Waha system is a 674-mile natural gas gathering system located in the Permian Basin region of Texas. The Carlsbad system is a 803-mile natural gas gathering system located in the Permian Basin region of New Mexico.

 

Acadian Gas System . The Acadian Gas System consists of three natural gas pipelines: the 577-mile Cypress pipeline, 438-mile Acadian pipeline, and the 27-mile Evangeline pipeline. The Acadian Gas System is involved in the purchase, sale, transportation and storage of natural gas in Louisiana. Enterprise Products Partners also leases a natural gas storage cavern with approximately 3 Bcf of capacity that is an integral part of this system.

 

Alabama Intrastate System . The Alabama Intrastate System is a natural gas pipeline system that serves the coal bed methane-producing regions of Alabama. This system provides transportation and marketing services through the purchase of natural gas from regional producers and others, and sale of natural gas to local distribution companies and others.

 

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Delmita Gathering System . The Delmita system is a natural gas gathering system located in South Texas that connects approximately 140 producing wells to its Delmita natural gas processing facility. This gathering system is an integral part of the natural gas processing operations of the Delmita facility, the results of operations and assets of which are accounted for under its NGL Pipelines & Services business segment.

 

Big Thicket Gathering System . The Big Thicket Gathering System, located in East Texas, gathers natural gas production from area fields and delivers the natural gas to its Indian Springs natural gas processing facility. This gathering system is an integral part of its Indian Springs natural gas processing operations, the results of operations and assets of which are accounted for under its NGL Pipelines & Services business segment.

 

Indian Springs Gathering System . In January 2005, Enterprise Products Partners acquired Teco Gas Gathering, LLC from El Paso Corporation, which provided Enterprise Products Partners with an indirect 80% interest in the Indian Springs Gathering System. The Indian Springs system consists of three gathering pipelines located in East Texas that gather natural gas production primarily from area fields and deliver the natural gas to its Indian Springs natural gas processing facility.

 

Natural Gas Storage Facilities

 

Enterprise Products Partners owns two underground salt dome natural gas storage facilities located near Hattiesburg, Mississippi that are strategically situated to serve the Northeast, Mid-Atlantic and Southeast natural gas markets. These two facilities have a combined current certificated working storage capacity of 13.5 Bcf, and are capable of delivering in excess of 1.2 Bcf/d of natural gas into five interstate pipeline systems: Transco, Destin Pipeline, Gulf South Pipeline, Southern Natural Gas Pipeline and Tennessee Gas Pipeline. Enterprise Products Partners also leases a natural gas storage facility in Texas having 6.4 Bcf of working storage capacity and lease a salt dome natural gas cavern in Louisiana having a working storage capacity of 3 Bcf.

 

The ability of these facilities to handle high levels of injections and withdrawals of natural gas makes them well-suited for customers who desire the ability to meet load swings and to cover major supply interruption events, such as hurricanes and temporary losses of production. The high injection and withdrawal rates also allow customers to take advantage of favorable natural gas prices and also provide customers the opportunity to quickly respond in situations where they have natural gas imbalance issues on pipelines connected to the storage facility. The characteristics of the salt domes at these facilities permit sustained periods of high delivery, the ability to quickly switch from full injection to full withdrawal and the ability to provide an impermeable storage medium.

 

Salt dome storage caverns such as those utilized at its Petal and Hattiesburg storage facilities experience a loss of working capacity of approximately 1% per year due to physical properties of the salt domes. Enterprise Products Partners address this normal loss of working capacity at its Petal and Hattiesburg storage through a flooding program.

 

A large portion of the revenue generated by its Petal and Hattiesburg storage facilities is based on fixed monthly demand payments, which are paid regardless of the customer’s usage of the storage facilities. The remaining revenues are primarily generated based on a storage fee per unit of volume stored at these facilities. Seasonality impacts the timing of injections and withdrawals at its natural gas storage facilities. In the winter months, natural gas is needed as fuel for residential and commercial heating, and during the summer months, natural gas is needed by gas-fired electric generation facilities due to the demand for electricity to power air conditioners.

 

Competition for natural gas storage is primarily based on location and the ability to deliver natural gas in a timely and reliable manner. Enterprise Products Partners’ Hattiesburg natural gas storage facilities are located in an area in Mississippi that effectively services the Northeastern, Mid-Atlantic and Southeastern natural gas markets, and these facilities have the ability to deliver all of their stored natural gas within a short duration. Enterprise Products Partners’ natural gas storage facilities compete with other means of natural gas storage, including other salt dome storage facilities, depleted reservoir facilities, and liquified natural gas and pipelines.

 

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Most of its Petal storage facility’s working capacity is dedicated under a 20-year, fixed-fee contract. Most of the contracts relating to the Hattiesburg and Wilson natural gas storage facilities expire between 2005 and 2007. Enterprise Products Partners believes that the location of its natural gas storage facilities should allow it to compete effectively with other companies who provide natural gas storage services. Enterprise Products Partners believes that many of its natural gas storage contracts will be renewed, although Enterprise Products Partners also expects that once these firm storage contracts have expired, Enterprise Products Partners will experience greater competition for providing storage services. The competition Enterprise Products Partners experiences will be dependent upon the nature of the natural gas storage market existing at that time. In addition to long-term contracts, Enterprise Products Partners actively markets interruptible storage services at the Petal facility to enhance its revenue generating ability beyond the firm storage contracts.

 

The following table summarizes the gross working gas capacity of its primary natural gas storage facilities and its ownership interest in each facility as of March 1, 2005.

 

Natural Gas Storage Facilities


  

Working Gas(1)
Capacity,

(Bcf)


  

Enterprise
Products
Partners’
Ownership

Interest


 

Petal

   9.5    100 %

Hattiesburg

   4.0    100 %

Wilson(2)

   6.4    Leased  

Acadian(3)

   3.0    Leased  

(1) Working gas is the volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility. This is the natural gas that is being stored and withdrawn. Working gas differs from “base gas” or “cushion gas,” which is the volume of gas that must remain in the storage facility to provide the minimum required pressurization to extract the working gas. The Petal working gas capacity is certificated by the FERC and the Hattiesburg working gas capacity is certificated by the Mississippi Oil and Gas Board.
(2) Enterprise Products Partners leases the Wilson natural gas storage facility under an operating lease that expires in January 2008.
(3) Enterprise Products Partners leases the Acadian natural gas storage cavern under an operating lease that expires in December 2012. This storage facility is an integral component of its Acadian Gas System.

 

The following is a brief description of each of Enterprise Products Partners’ owned and leased natural gas storage facilities:

 

Petal . The Petal storage facility is located near Hattiesburg, Mississippi and consists of two high-deliverability natural gas storage caverns. The Petal facility has a current injection capacity in excess of 430 MMcf/d of natural gas and a withdrawal capacity of 895 MMcf/d of natural gas. The Petal storage capacity is 94% subscribed, with 7 Bcf dedicated under a 20-year fixed-fee contract to a subsidiary of The Southern Company and 1.65 Bcf subscribed to BP Energy Company. Enterprise Products Partners is in the process of expanding this storage facility. For information regarding this expansion project, please read “—Major Construction Projects—Petal Conversion Project.”

 

Hattiesburg . The Hattiesburg storage facility is located less than one mile from the Petal storage facility and consists of three high-deliverability natural gas storage caverns. The facility has an injection capacity in excess of 175 MMcf/d of natural gas and a withdrawal capacity in excess of 400 MMcf/d of natural gas. The Hattiesburg capacity is currently fully subscribed, primarily with eleven contracts expiring between 2005 and 2007.

 

Wilson . The Wilson storage facility interconnects with Enterprise Products Partners’ Texas Intrastate System and consists of four caverns. The facility, located in Wharton County, Texas, has an injection capacity of 150 to 360 MMcf/d of natural gas and a withdrawal capacity of 800 MMcf/d of natural gas. The Wilson capacity is currently 96% subscribed with contracts expiring between 2006 and 2007.

 

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Acadian . The Acadian natural gas storage cavern is a rapid-cycle salt dome located in Assumption Parish, Louisiana that is an integral part of its Acadian Gas System. This storage facility has an injection capacity of 80 MMcf/d and a withdrawal capacity of 220 MMcf/d and is primarily used in the management of natural gas volumes on the Acadian Gas System; therefore, it is not generally used as a storage cavern for third-party customers.

 

Major Construction Projects

 

Petal Conversion Project . In the third quarter of 2004, Enterprise Products Partners began to convert an existing brine well at its existing propane storage complex in Hattiesburg, Mississippi to natural gas service. This conversion, which is expected to cost $18 million, will create a new natural gas storage cavern with 1.8 Bcf of working gas capacity that will be integrated with its existing Petal natural gas storage facility. Enterprise Products Partners expects to have the cavern in service during the second quarter of 2005. Enterprise Products Partners has executed long-term storage agreements with BP for the entire capacity of the new natural gas storage cavern.

 

San Juan Optimization Project . In May 2003, Enterprise Products Partners commenced a project relating to its San Juan Basin assets. This project, which is estimated to cost approximately $43 million, is expected to be completed in stages through 2006 and will result in increased capacity of up to 130 MMcf/d on its San Juan natural gas gathering system and increased market opportunities through a new interconnect at the tailgate of its Chaco plant.

 

Intangible Assets

 

At December 31, 2004, the Onshore Natural Gas Pipelines & Services segment included $425.8 million of intangible assets primarily related to customer relationships and other contract-based rights that Enterprise Products Partners owns. For information regarding its intangible assets, please read Note 8 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

NGL Pipelines & Services

 

Enterprise Products Partners’ NGL Pipelines & Services business segment includes its (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,775 miles and related storage facilities, which include its strategic Mid-America and Seminole NGL pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes its import and export terminaling operations.

 

In general, NGL products (ethane, propane, normal butane, isobutane and natural gasoline) are used as raw materials by the petrochemical industry, feedstocks by refiners in the production of motor gasoline and by industrial and residential users as fuel. Ethane is primarily used in the petrochemical industry as feedstock for ethylene production, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating, engine and industrial fuel. Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization. Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, principally for use in refinery alkylation to enhance the octane content of motor gasoline, in the production of iso-octane and MTBE, and in the production of propylene oxide. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline or as a petrochemical feedstock.

 

Natural Gas Processing and Related NGL Marketing Activities

 

At the core of Enterprise Products Partners’ natural gas processing business are 24 processing plants located in Texas, Louisiana, Mississippi and New Mexico, 11 of which were acquired in connection with the GulfTerra

 

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merger. In January 2005, Enterprise Products Partners acquired Teco Gas Processing, LLC from El Paso Corporation, which provided Enterprise Products Partners with an indirect 75% interest in the Indian Springs natural gas processing facility. The Indian Springs processing facility, which is located in Polk County, Texas, has capacity to process up to 120 MMcf/d of natural gas and there is an idle 20 MMcf/d production train available for restart to support increases in natural gas volumes. The natural gas processed at the Indian Springs processing facility is sourced from its Indian Springs Gathering System, which Enterprise Products Partners also acquired an interest in from El Paso Corporation in January 2005, as well as its nearby Big Thicket Gathering System.

 

In general, natural gas produced at the wellhead and in association with crude oil contains varying amounts of NGLs. This “rich” natural gas in its raw form is usually not acceptable for transportation in the nation’s major natural gas pipeline systems or for commercial use as a fuel. Natural gas production from the deepwater Gulf of Mexico and the Rocky Mountains, thus far, has generally been rich in NGLs and typically must be processed to meet pipeline quality specifications. Deepwater natural gas production can yield in excess of 4 gallons of NGLs per Mcf of natural gas processed versus an approximate 1 to 1.5 gallons of NGLs per Mcf of production from the continental shelf areas of the Gulf of Mexico.

 

Enterprise Products Partners’ natural gas processing facilities can be categorized as two distinct types: (1) straddle plants situated on mainline natural gas pipelines owned either by Enterprise Products Partners or by third parties or (2) field plants that process natural gas through associated gas gathering systems. Natural gas processing plants remove the NGLs from the natural gas stream, enabling the natural gas to meet transmission pipeline and commercial quality specifications. In addition, on an energy equivalent basis, NGLs generally have a greater economic value as a raw material for petrochemicals and motor gasoline than their value as components of the natural gas stream. After extraction, Enterprise Products Partners typically transports the mixed NGLs to a centralized facility for fractionation into purity NGL products such as ethane, propane, normal butane, isobutane and natural gasoline. The purity NGL products can then be used in its NGL marketing activities to meet contractual requirements or sold on spot and forward markets.

 

Enterprise Products Partners’ natural gas processing business and NGL marketing activities encounter competition from fully integrated oil companies, intrastate pipeline companies, major interstate pipeline companies and their non-regulated affiliates, and independent processors. Each of its competitors has varying levels of financial and personnel resources, and competition generally revolves around price, service and location issues. Enterprise Products Partners’ integrated midstream energy asset system affords it flexibility in meeting its customers’ needs. While many companies participate in the natural gas processing business, few have a presence in significant downstream activities such as NGL fractionation and transportation, import/export services and NGL marketing as Enterprise Products Partners does. Its competitive position and presence in these downstream businesses allows it to extract incremental value while offering its customers enhanced services, including comprehensive service packages.

 

In general, Enterprise Products Partners provides natural gas processing services under five types of arrangements: percent-of-liquids contracts, margin-band contracts, fee-based contracts, hybrid contracts (mixed percent-of-liquids and fee-based) and keepwhole contracts. The key features of each type of contract are described below:

 

    Percent-of-liquids contracts . Under this type of agreement, Enterprise Products Partners receives a percentage of mixed NGLs extracted from a producer’s natural gas stream. The producer either retains title to or receives the value associated with the remaining percentage of mixed NGLs extracted and is responsible for the cost of PTR with respect to 100% of the mixed NGLs extracted. Enterprise Products Partners derives a profit from percent-of-liquids arrangements to the extent that revenues from its sale and delivery of the mixed NGLs it extracted exceed the sum of its plant operating costs and any other costs such as fractionation and pipeline fees that it might incur. At December 31, 2004, approximately 33% of the natural gas volumes Enterprise Products Partners processed were done so under percent-of-liquids contracts.

 

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    Margin-band contracts . Under this type of agreement, Enterprise Products Partners takes ownership of mixed NGLs extracted from a producer’s natural gas stream. In return, Enterprise Products Partners pays the producer consideration based upon the energy value of the mixed NGLs it extracts from the natural gas stream and that of the fuel consumed by its plant in the extraction process. Collectively, these energy values are referred to as plant thermal reduction, which we refer to as PTR. The consideration Enterprise Products Partners pays to a producer is generally based on the price of natural gas multiplied by the quantity of PTR extracted or used; however, such consideration is reduced based on the total volume of gas that Enterprise Products Partners processes. Enterprise Products Partners derives a profit from these arrangements to the extent that revenues from its sale and delivery of the mixed NGLs it extracted exceed the sum of the consideration (which may be further adjusted as described below) paid to the producer, its plant operating costs and any other costs such as fractionation and pipeline fees that Enterprise Products Partners might incur. At December 31, 2004, approximately 26% of the natural gas volumes Enterprise Products Partners processed were done so under margin-band contracts.

 

    The most significant contract of this type affecting its natural gas processing business is the Shell agreement, which grants Enterprise Products Partners the right to process Shell’s current and future production within state and federal waters of the Gulf of Mexico. The Shell processing agreement includes a life of lease dedication, which may extend the agreement well beyond its initial 20-year term ending in 2019. This contract was amended effective April 1, 2004 to include (1) the reduction in consideration based upon the total volume of gas processed, and (2) a revision to the consideration adjustment outside of normal operations, or CAONO, mechanism discussed below. In general, the amended contract includes the following rights and obligations:

 

    the exclusive right, but not the obligation in all cases, to process substantially all of Shell’s Gulf of Mexico natural gas production; plus

 

    the exclusive right, but not the obligation in all cases, to process all natural gas production from leases dedicated by Shell for the life of such leases; plus

 

    the right to all title, interest and ownership in the mixed NGLs extracted by its gas processing plants from Shell’s natural gas production from such leases; with

 

    the obligation to re-deliver to Shell the natural gas stream after any mixed NGLs are extracted.

 

The amended contract contains a revised mechanism (termed “Consideration Adjustment Outside of Normal Operations” or “CAONO”) to adjust the value of the consideration Enterprise Products Partners pays to Shell. The revised CAONO provides for an economic “floor” which, in conjunction with the reduction in consideration that Enterprise Products Partners pays based on the total volume of gas processed, provides it with an acceptable return on the processing of Shell’s gas and provides Shell with relative assurance that its gas will continue to be processed during periods when gas processing economics are negative (times when Enterprise Products Partners would normally choose not to process Shell’s gas). The revised CAONO also provides for an economic “ceiling” whereby Shell receives certain portions of the economic gain Enterprise Products Partners realizes when such gains reach certain threshold levels.

 

    Fee-based contracts . Under this type of agreement, Enterprise Products Partners earns a fee based on the volume of natural gas Enterprise Products Partners processes. The producer either retains title to or receives the value associated with any mixed NGLs extracted and is responsible for all PTR costs. Enterprise Products Partners derives a profit from fee-based arrangements to the extent that the fees Enterprise Products Partners earns are greater than its plant operating costs. At December 31, 2004, approximately 18% of the natural gas volumes Enterprise Products Partners processed were done so under fee-based contracts.

 

   

Hybrid contracts . Under this type of agreement, Enterprise Products Partners typically provides processing services to a producer under a percent-of-liquids arrangement with the producer having a processing election on a monthly basis. In general, if a producer elects to not process under a percent-of-

 

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liquids arrangement, Enterprise Products Partners processes the natural gas under either a fee-based arrangement or in certain cases on a keepwhole basis if Enterprise Products Partners realizes greater economic gain. The intent of such arrangements is to give both producers and processors the incentive to process natural gas during periods of natural gas price volatility, especially during those periods when the price of natural gas is high relative to the economic value of NGLs. At December 31, 2004, approximately 14% of the natural gas volumes Enterprise Products Partners processed were done so under hybrid contracts.

 

    Keepwhole contracts . Under this type of agreement, Enterprise Products Partners takes ownership of mixed NGLs extracted from a producer’s natural gas stream and in return, Enterprise Products Partners either returns a quantity of natural gas with equivalent energy value as the PTR or pays the producer for the market value of the PTR. At December 31, 2004, approximately 9% of the natural gas volumes Enterprise Products Partners processed were done so under keepwhole contracts.

 

In general, Enterprise Products Partners’ percent-of-liquids, hybrid and keepwhole contracts give it the right (but not the obligation) to process natural gas for a producer; thus, Enterprise Products Partners is protected from processing at an economic loss during times when the sum of its costs exceeds the value of the mixed NGLs of which it would take ownership. Generally, its natural gas processing agreements have terms ranging from month-to-month to life of the producing lease. Intermediate terms of one to ten years are also common.

 

As noted previously, under certain processing arrangements, Enterprise Products Partners takes title to a portion of the mixed NGLs that are extracted by its natural gas processing plants. Once this mixed NGL volume is fractionated into purity NGL products (ethane, propane, normal butane, isobutane and natural gasoline), Enterprise Products Partners uses them to meet contractual requirements or sells them on spot and forward markets as part of its NGL marketing activities. As part of these marketing activities, Enterprise Products Partners has a number of isobutane sales contracts. To fulfill its obligations under these sales contracts, Enterprise Products Partners can purchase isobutane on the open market for resale, sell isobutane from its inventory or pay its isomerization business (which is part of the Petrochemical Services segment) a toll processing fee to process its inventories of imported or domestically-sourced normal and mixed butanes into isobutane. The intersegment expense and revenue recorded as a result of utilizing the services of its isomerization business is eliminated in consolidation.

 

In support of its commercial goals, Enterprise Products Partners’ NGL marketing activities within this segment rely on inventories of mixed NGLs and purity NGL products. These inventories are the result of accumulated equity NGL production volumes, imports and other spot and contract purchases. Enterprise Products Partners’ inventories of ethane, propane and normal butane are typically higher in summer months as each are in higher demand and at higher price levels during winter months. Isobutane and natural gasoline inventories are generally stable throughout the year. Enterprise Products Partners’ inventory cycle begins in late-February to mid-March (the seasonal low point); builds through September; remains level until early December; before being drawn downs through winter until the seasonal low is reached again.

 

To the extent that Enterprise Products Partners is obligated under its margin-band/keepwhole gas processing contracts to pay compensation based upon or replace the PTR extracted from the natural gas stream, Enterprise Products Partners is exposed to various risks, primarily commodity price fluctuations. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond its control. Periodically, Enterprise Products Partners attempts to mitigate these risks through the use of commodity financial instruments.

 

Some of its exposure to commodity price risk is mitigated because natural gas with a high content of NGLs must be processed in order to meet pipeline quality specifications and to be suitable for ultimate consumption. To the extent that natural gas is not processed and does not meet pipeline quality specifications, this unprocessed natural gas and its associated crude oil production may be subject to being shut-in (i.e., not produced). Therefore, producers are motivated to reach contractual arrangements that are acceptable to gas processors in order for gas

 

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processing services to be available on a continuous basis (e.g., through contracts that do not expose the processors to natural gas price fluctuations). During periods of extreme commodity price fluctuations, Enterprise Products Partners generally has the right under keepwhole arrangements to withhold processing services from a customer should Enterprise Products Partners and the producer be unsuccessful in reaching acceptable contractual arrangements.

 

The following table lists Enterprise Products Partners’ natural gas processing plants, total and net approximate processing capacities and its ownership interest in each facility at March 1, 2005. Enterprise Products Partners operates the Toca, North Terrebonne, Calumet, Neptune, and Chaco facilities and all of the Texas plants.

 

Natural Gas Processing Facility


   Location

   Approximate
Total Gas
Processing
Capacity
(Bcf/d)


   Enterprise
Products
Partners’
Ownership
Interest (1)


    Approximate
Net Gas
Processing
Capacity
(Bcf/d) (2)


Yscloskey

   Louisiana    1.85    29.4 %   0.54

Toca

   Louisiana    1.10    60.3 %   0.66

Venice

   Louisiana    1.30    13.1 %   0.17

North Terrebonne

   Louisiana    1.30    44.3 %   0.58

Calumet

   Louisiana    1.60    31.5 %   0.50

Blue Water

   Louisiana    0.95    7.4 %   0.07

Sea Robin

   Louisiana    0.95    15.5 %   0.15

Patterson II (3)

   Louisiana    0.60    1.9 %   0.01

Iowa

   Louisiana    0.50    2 %   0.01

Neptune

   Louisiana    0.65    66 %   0.43

Burns Point

   Louisiana    0.16    50 %   0.08

Pascagoula

   Mississippi    1.50    40 %   0.40

Chaco (4)

   New Mexico    0.65    100 %   0.65

Indian Basin (4)

   New Mexico    0.24    42.3 %   0.10

Thompsonville (4)

   Texas    0.30    100 %   0.30

Shoup (4)

   Texas    0.29    100 %   0.29

Gilmore (4)

   Texas    0.26    100 %   0.26

Armstrong (4)

   Texas    0.25    100 %   0.25

Matagorda (4)

   Texas    0.25    100 %   0.25

San Martin (4)

   Texas    0.20    100 %   0.20

Delmita (4)

   Texas    0.15    100 %   0.15

Shilling (4)

   Texas    0.11    100 %   0.11

Sonora (4)

   Texas    0.10    100 %   0.10

Indian Springs (5)

   Texas    0.12    75 %   0.09
         
        

Total natural gas processing facilities

        15.38          6.35
         
        

(1) Enterprise Products Partners owns direct consolidated interests in all of its natural gas processing facilities with the exception of Venice, which is part of its equity investment in VESCO.
(2) The approximate net natural gas processing capacity does not necessarily correspond to its ownership interest in each facility. It is based on a variety of factors including volumes processed at facility, ownership interest, contractual arrangements and other factors.
(3) This facility was idled in December 2004.
(4) Enterprise Products Partners acquired ownership interests in these facilities as a result of the GulfTerra merger.
(5) Enterprise Products Partners acquired its indirect ownership in this facility from El Paso Corporation in January 2005.

 

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The following table shows Enterprise Products Partners’ natural gas processing volumes and the corresponding overall utilization rates of its natural gas processing capacity for each of the last three years, with both amounts presented on a net basis in accordance with its ownership interests. The table also shows its equity NGL production for each of the last three years. Equity NGL production is defined as the volume of mixed NGLs extracted by the gas plants to which Enterprise Products Partners takes title under the terms of processing agreements or as a result of plant ownership interests.

 

     For Year Ended December 31,

 
         2004    

        2003    

        2002    

 

Net natural gas processing volume (Bcf/d)

   3.89     2.06     2.15  

Net natural gas processing capacity (Bcf/d)

   6.35     3.26     3.37  

Utilization rate

   61 %   63 %   64 %

Equity NGL production (MBbls/d)

   129 (2)   43 (1)   73  

Fee-based natural gas processing (MMcf/d)

   1,692 (2)   194        

(1) Equity NGL production rates for 2003 were adversely affected by high natural gas prices relative to the value of NGLs extracted. For additional information regarding natural gas and NGL prices, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Selected Price and Volumetric Information.”
(2) Equity NGL production and fee-based natural gas processing volumes were positively impacted by improved processing economics during 2004 and the addition of processing assets in connection with the GulfTerra merger.

 

As of December 31, 2004, Enterprise Products Partners’ NGL marketing activities utilize a fleet of approximately 569 railcars, the majority of which are under short and long-term leases. These railcars are used to deliver feedstocks to its facilities and to transport NGL products throughout the United States. Enterprise Products Partners has rail loading/unloading facilities at Mont Belvieu, Texas; Breaux Bridge, Louisiana; Sorrento, Louisiana and Petal, Mississippi. These facilities service both its rail shipments and those of its customers.

 

NGL Pipelines

 

Enterprise Products Partners’ NGL pipelines transport mixed NGLs and other hydrocarbons to fractionation plants, distribute and collect NGL products to and from petrochemical plants and refineries and deliver propane to customers along the Dixie pipeline and certain sections of the Mid-America Pipeline System. Enterprise Products Partners’ pipelines provide transportation services to customers on a fee basis. Therefore, the results of operations for this business are generally dependent upon the volume of product transported and the level of fees charged to customers (including its NGL and petrochemical marketing activities, which are eliminated in consolidation). Typically, its NGL pipelines do not take title to the products they transport; rather, the shipper retains title and the associated commodity price risk.

 

In the markets it serves, Enterprise Products Partners competes with a number of intrastate and interstate liquids pipeline companies (including those affiliated with major oil, petrochemical and gas companies) and barge, rail and truck fleet operators. In general, its NGL pipelines compete with these entities in terms of transportation fees and service. We believe that Enterprise Products Partners’ pipeline systems offer significant flexibility in rendering transportation services for its customers due to the large number of receipt and delivery points that it can offer to them.

 

Taken as a whole, this business area has not exhibited a significant degree of seasonality. However, propane transportation volumes are generally higher in the October through March timeframe due to increased use of propane for heating in the upper Midwest and southeastern United States. In addition, Enterprise Products Partners’ NGL pipeline systems are subject to various types of regulation. For a discussion of the general impact of governmental regulation on its business, please read “—Regulation and Environmental Matters.”

 

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The following table summarizes Enterprise Products Partners’ primary NGL pipeline transportation and distribution networks at March 1, 2005. Enterprise Products Partners’ ownership interest in each pipeline is held either through a consolidated subsidiary or indirectly through a company in which it has an investment accounted for under the equity method. For additional information regarding Enterprise Products Partners’ equity method investments, please read Note 7 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

NGL Pipelines


   Length
in Miles


   Enterprise
Products
Partners’
Ownership
Interest


 

Mid-America Pipeline System

   7,226    98 %

Dixie

   1,301    65.9 %(1)

Seminole

   1,281    88.4 %(2)

Texas NGL System(3)

   1,039    100 %

Louisiana Pipeline System

   655    Vario us(4)

Promix(5)

   410    50 %

Lou-Tex NGL

   206    100 %

HSC

   266    100 %

Tri-States

   169    66.7 %(6)

Chunchula

   143    100 %

Belle Rose

   48    41.7 %

Wilprise

   30    74.7 %
    
      

Total NGL pipelines

   12,774       
    
      

(1) Enterprise Products Partners acquired an additional 46.1% ownership interest in Dixie from ConocoPhillips (20%) and ChevronTexaco (26.1%) in January and February 2005, respectively.
(2) Enterprise Products Partners acquired an additional 10% ownership interest in Seminole from ChevronTexaco in May 2004.
(3) Acquired as a result of the GulfTerra merger on September 30, 2004.
(4) Of the 655 total miles for this system, Enterprise Products Partners owns 100% of 559 miles; 32.2% of 43 miles; and 44.3% of the remaining 53 miles.
(5) The Promix gathering pipeline is an integral component of the NGL fractionation activities of Promix. Enterprise Products Partners acquired an additional 16.7% ownership interest in Promix from Koch in December 2004.
(6) Enterprise Products Partners acquired an additional 16.7% ownership interest in Tri-States from Koch in April 2004.

 

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NGL pipeline utilization

 

The maximum number of barrels that these systems can transport per day depends upon the operating balance achieved at a given time between various segments of the systems. Because the balance is dependent upon the mix of products to be shipped and the demand levels at the various delivery points, the exact capacities of the systems cannot be stated. As showns in the following table, the utilization rates of Enterprise Products Partners’ primary NGL pipelines are measured in terms of throughput (on a net basis in accordance with its ownership interest).

 

    

Net Throughput Volumes (in MBbls/d)

For Year Ended December 31,


NGL Pipelines


         2004      

         2003      

         2002      

Mid-America Pipeline System(1)

   614    580    641

Dixie

   21    21    21

Seminole(1)

   235    194    202

Texas NGL System(2)

   38          

Louisiana Pipeline System

   216    190    179

Lou-Tex NGL

   20    36    38

HSC(3)

   135    136    134

Tri-States, Wilprise and Belle Rose

   61    35    44

Chunchula

   3    4    5
    
  
  

Total net volume of NGL pipelines

   1,343    1,196    1,264
    
  
  

(1) Enterprise Products Partners acquired ownership interests in these systems in July 2002. The 2002 throughput rates reflect the five-month period that Enterprise Products Partners owned interests in these assets (August 2002 through December 2002).
(2) Enterprise Products Partners acquired the Texas NGL System in connection with the GulfTerra merger on September 30, 2004. The 2004 throughput rates reflect the three-month period that Enterprise Products Partners owned this system (October 2004 through December 2004).
(3) Throughput volumes for 2004 include 22 MBbls/d from the 91 miles of NGL pipeline acquired with its Morgan’s Point facility in December 2004. Throughput rates are reflective of the period of time that Enterprise Products Partners owned the assets.

 

The following is a brief description of each of Enterprise Products Partners’ primary NGL pipeline assets, all of which it operates except for Dixie, Tri-States and a small portion of the Louisiana Pipeline System.

 

Mid-America Pipeline System . The Mid-America Pipeline System, or Mid-America, is a regulated NGL pipeline system consisting of three NGL pipelines: the 2,548-mile Rocky Mountain pipeline, the 2,740-mile Conway North pipeline, and the 1,938-mile Conway South pipeline. The Mid-America system crosses thirteen states: Wyoming, Utah, Colorado, New Mexico, Texas, Oklahoma, Kansas, Missouri, Nebraska, Iowa, Illinois, Minnesota and Wisconsin.

 

The Rocky Mountain pipeline transports mixed NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to the Hobbs hub located on the Texas-New Mexico border. The Conway North segment links the large NGL hub at Conway, Kansas, to refineries, petrochemical plants and propane markets in the upper Midwest. In addition, the Conway North segment has access to NGL supplies from Canada’s Western Sedimentary basin through third-party pipeline connections. The Conway South pipeline connects the Conway hub with Kansas refineries and transports NGLs from Conway, Kansas, to the Hobbs hub (with interconnections to the Seminole Pipeline System at the Hobbs hub). Enterprise Products Partners also owns fifteen unregulated propane terminals that are an integral part of the Mid-America system.

 

Approximately 60% of the volumes transported on the Mid-America system are mixed NGLs originating from natural gas processing plants located in the Permian Basin in West Texas, the Hugoton Basin of

 

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southwestern Kansas, the San Juan Basin of northwest New Mexico, and the Green River Basin of southwestern Wyoming. The remaining volumes are generally purity NGL products originating from NGL fractionators in the mid-continent areas of Kansas, Oklahoma, and Texas, as well as deliveries from Canada.

 

Dixie . The Dixie pipeline is a regulated propane pipeline system extending from Mont Belvieu, Texas and Louisiana to markets in the southeastern United States. Propane supplies transported on this system primarily originate from southeast Texas, southern Louisiana and Mississippi. Enterprise Products Partners purchased a 26.1% interest in Dixie from an affiliate of ChevronTexaco in February 2005 for $40 million, and a 20% interest in Dixie from an affiliate of ConocoPhillips in January 2005 for $31 million. As a result of these acquisitions, Dixie became a consolidated subsidiary of Enterprise Products Partners during the first quarter of 2005.

 

Seminole . Seminole is a regulated pipeline that transports mixed NGLs and NGL products from the Hobbs hub on the Texas-New Mexico border and the Permian Basin area to Mont Belvieu, Texas. The Seminole pipeline is interconnected with the Mid-America system at the Hobbs hub. The primary source of throughput for Seminole is the volume originating from the Mid-America system. In general, volumes transported by Seminole are ultimately used by petrochemical plants that manufacture various products in southeast Texas.

 

Texas NGL System . The Texas NGL System is a network of NGL gathering and transportation pipelines located in South Texas. The system includes 379-miles of pipeline used to gather and transport mixed NGLs from its South Texas natural gas processing facilities to its South Texas fractionation facilities. The pipeline system also includes approximately 660-miles of pipelines that deliver NGL products from its South Texas fractionation facilities to refineries and petrochemical plants located from Corpus Christi to Houston and within the Texas City-Houston area, as well as to common carrier NGL pipelines.

 

Louisiana Pipeline System . The Louisiana Pipeline System is a network of nine NGL pipelines located in Louisiana. This system transports mixed NGLs and NGL products originating in southern Louisiana and Texas and serves a variety of customers including major refineries and petrochemical companies along the Mississippi River corridor in southern Louisiana. This system also provides transportation services for its natural gas processing plants, NGL fractionators and other facilities located in Louisiana.

 

Promix . The Promix pipeline is a NGL pipeline system that gathers mixed NGLs from 12 natural gas processing plants in Louisiana for delivery to the Promix NGL fractionator. This pipeline system is an integral part of the Promix NGL fractionation facility.

 

Lou-Tex NGL . The Lou-Tex NGL pipeline system is used to provide transportation services for NGL products and refinery grade propylene between the Louisiana and Texas markets. Enterprise Products Partners also uses this pipeline to transport mixed NGLs from certain of its Louisiana gas processing plants to its Mont Belvieu NGL fractionation facility.

 

HSC . The Houston Ship Channel, or HSC, pipeline system is a collection of NGL and petrochemical pipelines extending from its Houston Ship Channel import/export terminal facility and Morgan’s Point Facility to Mont Belvieu, Texas. These pipelines are used to deliver NGL products to third-party petrochemical plants and refineries as well as to deliver feedstocks to its Mont Belvieu facilities. Additionally, the HSC pipeline system includes 91 miles of NGL pipeline acquired with its Morgan’s Point facility in December 2004.

 

Tri-States, Belle Rose and Wilprise . The Tri-States, Belle Rose and Wilprise NGL pipelines supply mixed NGLs to the BRF, Norco and Promix NGL fractionators located in Louisiana. The mixed NGLs transported on these systems originate from gas processing facilities located along the Mississippi, Alabama and Louisiana Gulf Coast.

 

Chunchula . The Chunchula pipeline system is a NGL pipeline system extending from the Alabama-Florida border to its NGL storage facilities at Petal, Mississippi for further distribution.

 

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NGL and Related Product Storage

 

Enterprise Products Partners’ NGL and related product storage facilities are integral parts of its operations. In general, its underground storage wells are used to store mixed NGLs, NGL products and petrochemical products for customers and itself. The profitability of its storage operations is primarily dependent upon the volume of material stored and the level of fees charged.

 

Enterprise Products Partners operates its storage facilities based on the needs and requirements of its customers in the NGL, petrochemical, heating and other related industries. Enterprise Products Partners usually experiences 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 downs for heating needs.

 

The following table summarizes gross working capacity of Enterprise Products Partners’ primary storage assets and its ownership of such capacity (on a net basis in accordance with its ownership interest) in each by state as of March 1, 2005. Enterprise Products Partners operates all of its owned or leased storage facilities, with the exception of certain assets operated for it by Shell in Louisiana and Mississippi.

 

NGL and Related Product Storage Assets by State


   Utilized
Working
Capacity,
MMBbls


   Enterprise
Products
Partners’
Ownership of
Working
Capacity,
MMBbls


Texas(1)

   113.9    95.5

Louisiana

   31.0    16.8

Mississippi(2)

   10.9    10.9

Iowa

   0.5    0.5

Nebraska

   0.3    0.3

Oklahoma

   0.1    0.1
    
  

Total NGL and Related Product storage capacity

   156.7    124.1
    
  

(1) The 113.9 million barrels, or MMBbls, of working capacity that Enterprise Products Partners utilizes in Texas includes 18.1 MMBbls held under operating leases assumed as a result of the GulfTerra merger.
(2) In connection with the GulfTerra merger, Enterprise Products Partners was required by the FTC to sell its pre-merger undivided 50% ownership in a Hattiesburg, Mississippi propane storage facility by December 31, 2004. Enterprise Products Partners sold its interest in this facility during the fourth quarter of 2004.

 

Enterprise Products Partners stores NGL and petrochemical products for customers in its storage facilities for a fee. The amount of storage capacity available for third party customer storage activity varies daily depending on its plant processing storage requirements. At times, Enterprise Products Partners provides some of its processing customers with short-term storage services (typically 30 days or less) at nominal fees when they cannot take immediate delivery of products. Segment revenues include fees charged to its NGL and petrochemical product marketing activities for their use of the storage facilities. These intrasegment revenues and offsetting expenses are eliminated in financial statement consolidation.

 

Enterprise Products Partners’ competitors in this area are integrated major oil companies, chemical companies and other storage and pipeline companies. Major oil and gas companies occasionally use their proprietary storage assets to store for third party customers, thereby entering into competition with Enterprise Products Partners and other storage capacity providers. Enterprise Products Partners competes with other storage service providers primarily in terms of the fees charged, number of pipeline connections and operational dependability.

 

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NGL Import and Export Facilities

 

Enterprise Products Partners leases and operates NGL import and export facilities and owns a barge dock located on the Houston Ship Channel in southeast Texas. Enterprise Products Partners’ import facility enables NGL tankers to be offloaded at their maximum unloading rate of 10,000 barrels per hour, thus minimizing the amount of time that a tanker is idle and increasing the number of vessels that can be offloaded. This NGL import facility is primarily used to offload volumes bound for its NGL storage and processing facilities near Mont Belvieu, Texas. In addition, Enterprise Products Partners owns an NGL export facility located at the same terminal as its import facility. Enterprise Products Partners’ export facility includes an NGL products chiller and related equipment used for loading refrigerated marine tankers for third-party export customers. Enterprise Products Partners’ export facility can load vessels with refrigerated propane and butane at rates up to 5,000 barrels per hour. In December 2004, Enterprise Products Partners acquired a barge dock having the capability to load or unload two barges simultaneously, at a maximum load-out rate of approximately 5,000 barrels per hour. Enterprise Products Partners’ combined NGL import and export volumes for the years ended December 31, 2004, 2003 and 2002 were 69 MBbls/d, 79 MBbls/d and 41 MBbls/d, respectively.

 

Enterprise Products Partners’ import and export operations compete with those operated by Dow, Dynegy and ChevronTexaco primarily in terms of loading and offloading volumes per hour. Enterprise Products Partners’ competitive position is enhanced because of its related storage and pipeline assets at Mont Belvieu, which allow it to load and offload ships very efficiently. The profitability of import and export activities primarily depends upon the available quantities of NGLs to be loaded and offloaded and the fees Enterprise Products Partners charges associated with each service. In general, its import volumes peak during the spring and summer months and its export volumes are at their highest levels during the winter months.

 

NGL Fractionation

 

NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane, normal butane and natural gasoline. 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. The mixed NGLs delivered from domestic natural gas processing plants and crude oil refineries to its NGL fractionation facilities are typically transported by NGL pipelines and, to a lesser extent, by railcar and truck.

 

Recoveries of mixed NGLs by gas processing plants represent the largest source of volumes processed by its NGL fractionators. When operating and extraction costs of gas processing plants are higher than the incremental value of the NGL products that would be received by NGL extraction, the recovery levels of certain NGL products such as ethane may be reduced. This leads to a reduction in volumes available for NGL fractionation. The increase or decrease in NGL recovery levels is a primary factor behind changes in gross fractionation volumes.

 

Based upon industry data, Enterprise Products Partners believes that sufficient volumes of mixed NGLs, especially those originating from Gulf Coast and Rocky Mountain natural gas processing plants, will be available for fractionation in commercially viable quantities for the foreseeable future. These gas processing plants are expected to benefit from anticipated increases in natural gas production from emerging deepwater developments in the Gulf of Mexico offshore Louisiana and in the Rockies. Deepwater natural gas production has historically had a higher concentration of NGLs than continental shelf or domestic land-based production along the Gulf Coast. In addition, through connections with its Mid-America and Seminole pipeline systems, its Mont Belvieu NGL fractionator has access to NGLs from additional major supply basins in North America, including the San Juan Basin NGL production areas. Lastly, significant volumes of mixed NGLs are contractually committed to its NGL fractionation facilities by joint owners and third-party customers.

 

The majority of Enterprise Products Partners’ NGL fractionation facilities process mixed NGL streams for third-party customers and to support its NGL marketing activities under fee-based arrangements. These fees

 

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(typically in cents per gallon) are subject to adjustment for changes in certain fractionation expenses, including natural gas fuel costs. At its Norco facility, Enterprise Products Partners performs fractionation services for certain customers under percent-of-liquids contracts whereby Enterprise Products Partners retains a percentage of the NGLs Enterprise Products Partners fractionates for them as its payment. The results of operations of its NGL fractionation business are dependent upon the volume of mixed NGLs fractionated and either the level of fractionation fees charged (under fee-based contracts) or the value of NGLs received (under percent-of-liquids arrangements). Enterprise Products Partners is exposed to fluctuations in NGL prices to the extent Enterprise Products Partners fractionates volumes for customers under percent-of-liquids arrangements. Enterprise Products Partners’ tolling (or fee-based) customers generally retain title to the NGLs that Enterprise Products Partners processes for them. Overall, the NGL fractionation business exhibits little to no seasonal variation.

 

Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and distribute NGL products is also an important competitive factor and is a function of the existence of the necessary pipeline and storage infrastructure. NGL fractionators connected to extensive transportation and distribution systems such as Enterprise Products Partners’ have direct access to larger markets than those with less extensive connections.

 

The following table summarizes Enterprise Products Partners’ primary NGL fractionation assets at March 1, 2005. Enterprise Products Partners’ ownership interest in each NGL fractionator is held either through a consolidated subsidiary or indirectly through a company in which Enterprise Products Partners has an investment accounted for under the equity method. For additional information regarding its equity method investments, please read Note 7 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

NGL Fractionation Facility


   Location

   Total Plant
Capacity,
MBbls/d


   Enterprise
Products
Partners’
Ownership
Interest


    Net Capacity,
MBbls/d


Mont Belvieu

   Texas    210    75.0 %   158

South Texas(1)

                    

Shoup

   Texas    69    100.0 %   69

Armstrong

   Texas    17    100.0 %   17

Delmita

   Texas    10    100.0 %   10

Promix

   Louisiana    145    50.0 %(2)   73

Norco

   Louisiana    75    100.0 %   75

BRF

   Louisiana    60    32.2 %   19

VESCO

   Louisiana    36    13.1 %   5

Tebone

   Louisiana    30    44.3 %   13
         
        

Total Capacity

        652          439
         
        

(1) Acquired as a result of the GulfTerra merger. This list excludes the Almeda NGL fractionation facility (24 MBbls/d of capacity) that was acquired in connection with the GulfTerra merger. At present, Enterprise Products Partners has no plans to resume operations at the Almeda location.
(2) Enterprise Products Partners acquired an additional 16.7% interest in Promix in December 2004.

 

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NGL fractionator utilization

 

The following table shows fractionation volumes and capacity (on a net basis in accordance with Enterprise Products Partners’ ownership interest) and the corresponding overall utilization rates of its primary NGL fractionation facilities for the last three years. Net capacity amounts have been adjusted for the timing of acquisitions and facility closures.

 

     For Year Ended December 31,

 

NGL Fractionation Facility


       2004    

        2003    

        2002    

 

Mont Belvieu

   137     134     127  

South Texas

   71              

Promix

   20     24     30  

Norco

   57     42     41  

BRF

   15     11     17  

Other

   7     16     20  
    

 

 

Total net volume (MBbls/d)

   307     227     235  
    

 

 

Net capacity (MBbls/d)

   439     324     313  
    

 

 

Utilization rate

   70 %   70 %   75 %
    

 

 

 

The following is a brief description of Enterprise Products Partners’ primary NGL fractionation assets, all of which Enterprise Products Partners operates except for VESCO.

 

Mont Belvieu . The Mont Belvieu NGL fractionator is one of the largest NGL fractionation facilities in the United States with a gross processing capacity of 210 MBbls/d. Enterprise Products Partners’ facility is located at Mont Belvieu, Texas, which is a key hub of the domestic and international NGL industry. Enterprise Products Partners’ Mont Belvieu facility fractionates mixed NGLs from several major NGL supply basins in North America including the Mid-Continent, Permian Basin, San Juan Basin, Rocky Mountain Overthrust, East Texas and the U.S. Gulf Coast. Enterprise Products Partners’ Mont Belvieu NGL fractionation facility is supported by long-term fractionation agreements, which accounted for 102 MBbls/d of net volume in 2004.

 

South Texas . The South Texas NGL fractionation facilities (Armstrong, Delmita and Shoup) have a combined capacity of 96 MBbls/d. These facilities physically occupy the same pad sites as certain of Enterprise Products Partners’ South Texas natural gas processing facilities. Primarily all of the NGLs fractionated at these facilities are supplied directly from the South Texas NGL processing facilities.

 

Promix . Promix owns a 145 MBbls/d NGL fractionation facility located near Napoleonville, Louisiana. Enterprise Products Partners acquired an additional 16.7% interest in Promix in December 2004, resulting in an increase in its ownership interest to 50%. Promix owns a 410-mile mixed NGL gathering system connected to twelve natural gas processing plants, five NGL storage caverns and a barge loading facility. Promix also receives mixed NGLs from natural gas processing plants on the Mississippi and Alabama Gulf Coast through a connection with its Belle Rose and Tri-States pipelines.

 

Norco . The Norco NGL fractionation facility, located in Norco, Louisiana, has a gross capacity of 75 MBbls/d. Enterprise Products Partners’ Norco facility receives mixed NGLs via pipeline from refineries and natural gas processing plants, including the Yscloskey and Toca natural gas processing plants in Louisiana. A portion of the mixed NGLs fractionated at its Norco facility are done so under percent-of-liquids contracts with the remainder of volumes fractionated under a fee-based contract. During 2004, long-term percent-of-liquids contracts exclusive to this facility accounted for approximately 51 MBbls/d of processing volume.

 

BRF . The BRF NGL fractionation facility, located near Baton Rouge, Louisiana, has a gross capacity of 60 MBbls/d. The BRF facility processes mixed NGLs provided by the co-owners of the facility (Williams, BP and

 

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Exxon Mobil) from production areas in Alabama, Mississippi and southern Louisiana including offshore Gulf of Mexico areas.

 

VESCO . As a result of its VESCO investment, Enterprise Products Partners owns a 13.1% interest in a 36 MBbls/d NGL fractionator located in Plaquemines Parish, Louisiana.

 

Tebone . The Tebone NGL fractionation facility, located in Ascension Parish, Louisiana, has a gross capacity of 30 MBbls/d. Enterprise Products Partners’ Tebone facility receives mixed NGLs from the North Terrebonne gas processing plant.

 

Major Construction Projects

 

Rocky Mountain NGL pipeline expansion and related NGL fractionation projects . In January 2005, Enterprise Products Partners started a project to expand its Mont Belvieu NGL fractionator to accommodate an expected increase in NGLs transported to Mont Belvieu from the Rocky Mountains area. Enterprise Products Partners’ Mont Belvieu facility’s current fractionation capacity is up to 210 MBbls/d of mixed NGLs. This project, which is expected to be completed in the first quarter of 2006 at an estimated total cost of $34.2 million, will increase total fractionation capacity at this facility by 15 MBbls/d and reduce its energy utilization costs. Additionally, Enterprise Products Partners has announced that it plans to construct a new NGL fractionator, designed to handle up to 75 MBbls/d of mixed NGLs, located at the interconnection of the Mid-America pipeline system and the Seminole pipeline system near Hobbs, New Mexico.

 

Currently, the Rocky Mountain segment of Enterprise Products Partners’ Mid-America pipeline system transports up to 225 MBbls/d of NGLs from the major producing basins in Wyoming, Utah, Colorado and New Mexico to the Hobbs station on the Texas-New Mexico border. The proposed Western Expansion Project would expand the NGL transportation capacity of this pipeline to 275 MBbls/d. Permitting, engineering and design work are in progress. Enterprise Products Partners submitted a draft environmental assessment and plan of development to the appropriate regulatory agencies during the first quarter of 2005. Contingent upon receiving all required permits and regulatory approvals, construction could begin as early as the fourth quarter of 2005.

 

Intangible Assets

 

At December 31, 2004, the NGL Pipelines & Services segment included $303.5 million of intangible assets primarily related to customer relationships and other contract-based rights that Enterprise Products Partners owns. For information regarding Enterprise Products Partners’ intangible assets, please read Note 8 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Petrochemical Services

 

Enterprise Products Partners’ Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex, and an octane additive production facility. This segment also includes various petrochemical pipeline systems.

 

Propylene Fractionation

 

Enterprise Products Partners’ propylene fractionation business consists primarily of four propylene fractionation facilities located in Texas and Louisiana, and approximately 460 miles of various propylene pipeline systems. In general, propylene fractionation plants separate refinery grade propylene (a mixture of propane and propylene) 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,

 

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houseware and medical products. Chemical grade propylene is a basic petrochemical used in plastics, synthetic fibers and foams. Overall, the propylene fractionation business exhibits little seasonality.

 

Enterprise Products Partners competes with numerous producers of polymer grade propylene, which include many of the major refiners on the Gulf Coast. Generally, the propylene fractionation business competes in terms of the level of toll processing fees charged and access to pipeline and storage infrastructure. Enterprise Products Partners’ petrochemical marketing activities encounter competition from fully integrated oil companies and various petrochemical companies. Each of its petrochemical marketing competitors has varying levels of financial and personnel resources and competition generally revolves around price, service, logistics and location issues.

 

The following table summarizes Enterprise Products Partners’ primary propylene fractionation assets and ownership at March 1, 2005. Enterprise Products Partners’ ownership interest in each propylene fractionation facility is held either directly through a consolidated subsidiary or indirectly through a company in which Enterprise Products Partners has an investment accounted for under the equity method. For additional information regarding Enterprise Products Partners’ equity method investments, please read Note 7 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Propylene Fractionation Facility


   Location

   Total Plan
Capacity,
MBbls/d


   Enterprise
Products
Partners’
Ownership
Interest


    Net Capacity,
MBbls/d


Mont Belvieu:

                    

Splitter I

   Texas    17    54.6 %(1)   17

Splitter II

   Texas    14    100.0 %   14

Splitter III

   Texas    41    66.7 %   27
         
        

Total Mont Belvieu

        72          58

BRPC

   Louisiana    23    30.0 %   7
         
        

Total Capacity

        95          65
         
        

(1) Enterprise Products Partners owns a 54.6% interest in Splitter I. Enterprise Products Partners leases the remaining 45.4% interest in this facility from an affiliate of Shell.

 

The following is a brief description of Enterprise Products Partners’ primary propylene fractionation assets, all of which it operates:

 

Mont Belvieu . Enterprise Products Partners operates three polymer grade propylene fractionation facilities (Splitters I, II and III) in Mont Belvieu, Texas having a combined net capacity of 58 MBbls/d. Results of operations for its polymer grade propylene plants are generally dependent upon toll processing arrangements and petrochemical marketing activities. Under toll processing arrangements, Enterprise Products Partners is paid fees based on the volume of refinery grade propylene used to produce polymer grade propylene.

 

As part of the petrochemical marketing activities associated with Splitters I, II, and III, Enterprise Products Partners has several long-term polymer grade propylene sales agreements, the largest of which is with an affiliate of Shell. To meet its petrochemical marketing obligations, Enterprise Products Partners has entered into several agreements to purchase refinery grade propylene. To limit the exposure of its petrochemical marketing activities to price risk, Enterprise Products Partners attempts to match the timing and price of its feedstock purchases with those of the sales of end products. During 2004, 11 MBbls/d of its net polymer grade propylene production was associated with toll processing operations with the balance attributable to petrochemical marketing activities.

 

BRPC . BRPC is a 23 MBbls/d chemical grade propylene production facility located near Baton Rouge, Louisiana. This unit, located across the Mississippi River from Exxon Mobil’s refinery and chemical plant,

 

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fractionates refinery grade propylene produced by Exxon Mobil into chemical grade propylene for a toll-processing fee.

 

The following table shows net fractionation volumes and capacity (in MBbls/d, on a net basis in accordance with its ownership interest) and the corresponding overall utilization rates of its propylene fractionation facilities for the last three years. Net capacity amounts have been adjusted for the timing of acquisitions.

 

     For Year Ended December 31,

 

Propylene Fractionation Facility


     2004  

      2003  

      2002  

 

Mont Belvieu

       51         53         51  

BRPC

   5     4     4  
    

 

 

Total net volume (MBbls/d)

   56     57     55  
    

 

 

Net capacity

   65     65     63  
    

 

 

Utilization rate

   86 %   88 %   87 %
    

 

 

 

Petrochemical Pipelines and Export Terminal

 

The following table summarizes Enterprise Products Partners’ primary petrochemical pipeline transportation and distribution networks at March 1, 2005. Enterprise Products Partners’ ownership interest in each pipeline is held either directly through a consolidated subsidiary or indirectly through a company in which Enterprise Products Partners has an investment accounted for under the equity method. For additional information regarding Enterprise Products Partners’ equity method investments, please read Note 7 of the Notes to Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Petrochemical Pipelines


   Length in
Miles


   Enterprise
Products
Partners’
Ownership
Interest


 

Lou-Tex Propylene

   291    100.0 %

Lake Charles/Bayport

   87    50.0 %(1)

Texas City

   28    100.0 %

Sabine Propylene

   21    100.0 %

La Porte(2)

   17    50.0 %

Morgan’s Point(3)

   13    100.0 %
    
      

Total petrochemical pipelines

   457       
    
      

(1) Of the 87 total miles for this pipeline, Enterprise Products Partners owns 50% of 82 miles and 100% of the remaining 5 miles.
(2) The La Porte pipeline is an integral component of the propylene fractionation activities of Splitter III.
(3) Enterprise Products Partners acquired a 13-mile petrochemical pipeline in December 2004 as part of its Morgan’s Point facility acquisition.

 

The following is a brief description of Enterprise Products Partners’ primary petrochemical pipeline assets, all of which it operates with the exception of the OTC Propylene Export Facility:

 

Lou-Tex Propylene . The Lou-Tex Propylene pipeline consists of a 291-mile pipeline used to transport propylene from Sorrento, Louisiana to Mont Belvieu, Texas. Currently, this pipeline is used to transport chemical grade propylene for third parties from production facilities in Louisiana to customers in Texas. This system also includes storage facilities and a 28-mile NGL pipeline.

 

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Lake Charles/Bayport . The Lake Charles/Bayport pipeline system is comprised of two pipelines: a 77-mile system used (in combination with a pipeline owned and operated by ExxonMobil) to distribute polymer grade propylene from Mont Belvieu, Texas to polypropylene plants in Lake Charles, Louisiana and Bayport, Texas; and approximately 10 miles of related polymer grade propylene pipelines located in the La Porte, Texas area.

 

Texas City . The Texas City pipeline connects Enterprise Products Partners’ 50% owned La Porte pipeline to various polymer grade propylene customers. This pipeline runs 28 miles south to 9 delivery locations and ends in the Texas, City, Texas area.

 

Sabine Propylene . The Sabine Propylene pipeline system is a 21-mile pipeline used to transport polymer grade propylene from third-party plant facilities in Port Arthur, Texas to a connection with its Lake Charles pipeline.

 

La Porte . The La Porte pipeline is a 17-mile pipeline used to distribute polymer grade propylene from Mont Belvieu, Texas to La Porte, Texas. This pipeline is an integral part of Enterprise Products Partners’ Mont Belvieu propylene fractionation activities.

 

Morgan’s Point . The Morgan’s Point Pipeline is a 13-mile propylene pipeline extending from Enterprise Products Partners’ facility at Morgan’s Point, Texas to the nearby Ellington Field.

 

OTC Propylene Export Facility . The OTC propylene export facility is an above-ground polymer grade propylene storage and export facility located in Seabrook, Texas. This facility can load vessels of polymer grade propylene at rates up to 5,000 barrels per hour. OTC’s primary competitor is an export operation owned by ChevronPhillips located on the Houston Ship Channel. OTC’s operations are an integral part of Enterprise Products Partners’ Mont Belvieu propylene fractionation business.

 

Petrochemical Pipeline and Export Terminal Utilization

 

The maximum number of barrels that Enterprise Products Partners’ petrochemical pipelines can transport per day depends upon the operating balance achieved at a given time between various segments of the system. Because the balance is dependent upon the mix of products to be shipped and the demand levels at the various delivery points, the exact capacity of the systems cannot be stated. Utilization of its primary petrochemical pipelines is measured in terms of throughput volumes. Utilization for OTC is measured in terms of volumes loaded. The following table shows the throughput volume for each asset over the last three years (in MBbls/d, on a net basis in accordance with its ownership interest).

 

     For Year Ended December 31,

         2004    

       2003    

       2002    

Lou-Tex Propylene

       28        29        25

Lake Charles/Bayport

   13    13    11

Sabine Propylene

   11    11    11

OTC

   6    3    4
    
  
  

Total net volume of petrochemical pipelines

   58    56    51
    
  
  

 

Butane Isomerization

 

At March 1, 2005, Enterprise Products Partners’ isomerization business includes three butamer reactor units and eight associated deisobutanizer units located in Mont Belvieu, Texas, which comprise the largest commercial isomerization complex in the United States. In addition, this business includes a 70-mile pipeline system used to transport high-purity isobutane from Mont Belvieu, Texas to Port Neches, Texas. Enterprise Products Partners’ isomerization facilities have an average combined production capacity of 116 MBbls/d of isobutane. Enterprise Products Partners owns and operates the isomerization facilities.

 

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Enterprise Products Partners’ commercial isomerization units convert normal butane into mixed butane, which is subsequently fractionated into normal butane, isobutane and high purity isobutane. The demand for commercial isomerization services depends upon the industry’s requirements for high purity isobutane and isobutane in excess of naturally occurring isobutane produced from NGL fractionation and refinery operations. Isobutane demand is marginally higher in the spring and summer months due to the demand for isobutane-based fuel additives in the production of motor gasoline. The results of operation of this business are generally dependent upon the volume of normal and mixed butanes processed and the level of toll processing fees charged to customers. The principal uses of isobutane are for alkylate used in the production of motor gasoline, propylene oxide and in the production of MTBE and iso-octane.

 

The Mont Belvieu isomerization facility provides processing services to meet the needs of third-party customers and its other businesses, including its NGL marketing activities and octane additive production facility. In general, Enterprise Products Partners’ third-party customers pay it a toll processing fee based on the volume of isobutane Enterprise Products Partners produce for them. Enterprise Products Partners’ NGL marketing activities utilize these facilities to convert normal and/or mixed butanes into isobutane in order to satisfy isobutane sales contracts. Enterprise Products Partners also uses its isomerization facility to meet the feedstock requirements of its octane additive production facility. The revenues and expenses Enterprise Products Partners records for such intercompany transactions are eliminated in consolidation. During 2004, 49 MBbls/d of its isobutane production was attributable to third party agreements, with the balance of 27 MBbls/d related to intercompany arrangements.

 

In the isomerization market, Enterprise Products Partners competes primarily with facilities located in Kansas, Louisiana and New Mexico. Competitive factors affecting this business include the level of toll processing fees charged, the quality of isobutane that can be produced and access to pipeline and storage infrastructure. Enterprise Products Partners believes that its isomerization facilities benefit from the integrated nature of its Mont Belvieu complex with its extensive connections to pipeline and storage assets.

 

The following table shows isobutane production and capacity and overall utilization of the Mont Belvieu facility for the last three years:

 

     For Year Ended December 31,

 

Mont Belvieu Isomerization Facility


   2004

    2003

    2002

 

Production (MBbls/d)

   76     77     84  

Net capacity (MBbls/d)

   116     116     116  

Utilization rate(1)

   66 %   66 %   72 %

(1) 2003 production and utilization rate decreased when compared to 2002 as a result of lower isobutane feedstock demand from BEF.

 

Octane Enhancement

 

Enterprise Products Partners owns a 100% interest in BEF, which owns an octane additive production facility designed to produce both iso-octane and MTBE, which are motor gasoline additives that increase octane and are used in reformulated motor gasoline blends. Enterprise Products Partners operates the facility, which is located within its Mont Belvieu complex. On September 30, 2003, Enterprise Products Partners purchased an additional 33.3% interest in this facility, at which time BEF became a majority-owned consolidated subsidiary of ours. On September 1, 2004, Enterprise Products Partners acquired the remaining 33.3% interest in BEF.

 

Prior to 2005, BEF primarily produced MTBE, the production of which was primarily driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990. In recent years, MTBE has been detected in water supplies. The major source of ground water contamination appears to be leaks from underground storage tanks. As a result of environmental concerns, several states have enacted legislation to ban or significantly limit the use of MTBE in motor gasoline within their jurisdictions. In addition, federal legislation

 

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has been drafted to ban MTBE and replace the oxygenate with renewable fuels such as ethanol. Although numerous resulting legal actions have been filed against motor gasoline and MTBE producers, BEF has not been named in any MTBE legal action to date.

 

As a result of these developments, Enterprise Products Partners is in the process of modifying the facility to also produce iso-octane, a motor gasoline octane enhancement additive derived from isobutane. Enterprise Products Partners expects iso-octane to be in demand by refiners to replace the amount of octane that is lost as a result of MTBE being eliminated as a motor gasoline blendstock. Depending on the outcome of various factors (including pending federal legislation) the facility may be further modified in the future to produce alkylate.

 

BEF produces iso-octane using feedstocks of high-purity isobutane and MTBE using both high-purity isobutane and methanol. The high-purity isobutane feedstock requirements are met using production from its Mont Belvieu isomerization units. BEF’s methanol requirements for MTBE production are met through spot market purchases. Enterprise Products Partners competes with other octane additive manufacturing companies primarily on the basis of price. Historically, MTBE prices have been stronger during the April to September period of each year, which corresponds with the summer driving season. Enterprise Products Partners expects to experience the same seasonal demand for iso-octane. BEF’s iso-octane production can be transported using its HSC Pipeline to a location on the Houston Ship Channel for delivery to customers.

 

As a result of declining domestic demand and a prolonged period of weak MTBE production economics, several of BEF’s competitors announced their withdrawal from the marketplace during 2003. Due to the deteriorating business environment and outlook and the completion of its preliminary engineering studies regarding conversion alternatives, BEF evaluated the carrying value of its long-lived assets for impairment during the third quarter of 2003. This review indicated that the carrying value of its long-lived assets exceeded their collective fair value, which resulted in a non-cash asset impairment charge of $67.5 million. Enterprise Products Partners’ share of this loss was $22.5 million and is recorded as a component of “Equity in income (loss) of unconsolidated affiliates” in Enterprise Products GP’s Statements of Consolidated Operations and Comprehensive Income for the year ended December 31, 2003.

 

The following table shows BEF’s historical MTBE production volumes and capacity (on a net basis in accordance with its ownership interest) and the corresponding overall utilization rates of the BEF facility for the last three years. Net capacity for 2004 and 2003 has been adjusted for its September 2004 and September 2003 acquisitions of the additional 33.3% interests in the facility.

 

     For Year Ended December 31,

 

BEF Facility


     2004  

      2003  

      2002  

 

Gross MTBE production capacity (MBbls/d)

   16.5     16.5     16.5  

Net MTBE production capacity (MBbls/d)

   9.4     7.0     5.5  

Net MTBE production volume (MBbls/d)

   7.8     4.4     5.1  

Utilization rate

   83 %   62 %   94 %

 

Intangible Assets

 

At December 31, 2004, the Petrochemical Services segment included $51.3 million of intangible assets primarily related to contract-based rights that Enterprise Products Partners owns. For information regarding its intangible assets, please read Note 8 of the Notes to the December 31, 2004 Consolidated Financial Statements of Enterprise Products GP.

 

Employees

 

Enterprise Products Partners does not have any employees. EPCO employs most of the persons necessary for the operation of its business. At December 31, 2004, EPCO had approximately 2,345 employees involved in

 

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the management and operations of its business, none of whom were members of a union. Enterprise Products Partners fully reimburses EPCO for the costs of all 2,345 employees. For a detailed discussion of its related party transactions with EPCO, please read “Certain Relationships and Related Party Transactions.” In addition to EPCO employees, Enterprise Products Partners has engaged approximately 261 contract maintenance and other personnel who support its operations.

 

Major Customers

 

Enterprise Products Partners’ revenues are derived from a wide customer base. Enterprise Products Partners’ largest customer, Shell, accounted for 6.5%, 5.5% and 7.9% of its consolidated revenues in 2004, 2003 and 2002, respectively.

 

Regulation and Environmental Matters

 

Regulation of Enterprise Products Partners’ Interstate Common Carrier Liquids Pipelines

 

Enterprise Products Partners’ Mid-America, Seminole, Chunchula, Lou-Tex Propylene and Lou-Tex NGL pipelines and certain pipelines in which Enterprise Products Partners owns equity interests (Dixie, Tri-States, Wilprise and Belle Rose), along with certain pipelines of the Louisiana Pipeline System, are interstate common carrier liquids pipelines subject to regulation by the FERC under the October 1, 1977 version of the Interstate Commerce Act, or ICA.

 

As interstate common carriers, these pipelines provide service to any shipper who requests transportation services, provided that products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. The ICA requires Enterprise Products Partners to maintain tariffs on file with the FERC that set forth the rates Enterprise Products Partners charges for providing transportation services on its interstate common carrier pipelines as well as the rules and regulations governing these services.

 

The ICA gives the FERC authority to regulate the rates Enterprise Products Partners charges for service on the interstate common carrier pipelines. The ICA requires, among other things, that such rates be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge proposed new or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff during the term of the investigation. The FERC may also investigate, upon complaint or on its owns motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

 

On October 24, 1992, Congress passed the Energy Policy Act of 1992, or the Energy Policy Act. The Energy Policy Act deemed petroleum pipeline rates that were in effect for the twelve months preceding enactment that had not been subject to complaint, protest or investigation to be just and reasonable under the ICA (i.e., “grandfathered”). The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. In order to challenge grandfathered rates, a party would have to show that it was previously contractually barred from challenging the rates, or that the economic circumstances of the oil pipeline that were a basis for the rate or the nature of the service underlying the rate had substantially changed or that the rate was unduly discriminatory or preferential.

 

The Energy Policy Act required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for petroleum pipelines, and to streamline procedures in petroleum pipeline proceedings. The FERC responded to this mandate by issuing Order No. 561, which, among other things, adopted an indexing rate methodology for petroleum pipelines. Under the regulations, which became effective January 1, 1995, petroleum pipelines are able to change their rates within prescribed ceiling levels that are tied to

 

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an inflation index. Rate increases made within the ceiling levels will be subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. If the indexing methodology results in a reduced ceiling level that is lower than a pipeline’s filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling. Under Order No. 561, a pipeline may as a general rule utilize the indexing methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market-based rates, and settlement as alternatives to the indexing approach. While there has been some activity regarding challenge to grandfathered rates in an on-going case against SFPP, L.P., or SFPP, an unrelated interstate common carrier for refined products in the western United States, requirements for such a challenge remain uncertain. Portions of Enterprise-owned liquid pipelines have established rates meeting the grandfathering provisions.

 

We believe that the rates Enterprise Products Partners charged for transportation services on the interstate pipelines it owns or have an interest in are just and reasonable under the ICA. However, we cannot predict what rates Enterprise Products Partners will be allowed to charge in the future for service on its interstate common carrier pipelines. Furthermore, because rates charged for transportation services must be competitive with those charged by other transporters, the rates set forth in its tariffs will be determined based on competitive factors in addition to regulatory considerations.

 

In December 1999, GulfTerra Texas (formerly EPGT Texas) filed a petition with the FERC for approval of its rates for interstate transportation service pursuant to Section 311 of the Natural Gas Policy Act of 1978, or NGPA. In June 2002, the FERC issued an order that required revisions to GulfTerra Texas’ proposed maximum rates. The changes ordered by the FERC involve reductions to rate of return and depreciation rates, and revisions to the proposed rate design, including a requirement to state separately rates for gathering service. The FERC also ordered refunds to customers for the difference, if any, between the originally proposed levels and the revised rates ordered by the FERC. On February 25, 2004, the FERC denied GulfTerra Texas’ request for rehearing and ordered GulfTerra Texas to file a calculation of refunds and a refund plan. GulfTerra Texas filed that information with the FERC on July 12, 2004. The FERC, by letter dated January 11, 2005, is seeking additional information from GulfTerra Texas regarding its filing, and, thus, a final FERC order is still pending. Additionally, the FERC rejected GulfTerra Texas’ rehearing request as to a requirement to file a new rate case or justification of existing rates every three years.

 

Last year, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in BP West Coast Products, LLC v. FERC , addressing the rate of SFPP, a publicly traded limited partnership. The Court (i) upheld the FERC’s determination that some of SFPP’s rates were grandfathered rates under the Energy Policy Act and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification of those rates; (ii) eliminated the tax allowance in SFPP’s rates because the SFPP limited partnership did not have tax liability; and (iii) remanded the issue of whether SFPP’s revised cost of service without the tax allowance would qualify as a substantially changed circumstance that would justify modification of SFPP’s rates. On May 4, 2005, the FERC issued a policy statement providing that all entities owning public utility assets—oil and gas pipelines and electric utilities—would be permitted to include an income tax allowance in their rates to reflect the actual or potential income tax liability attributable to their public utility income, regardless of the form of ownership. Any tax pass-through entity seeking an income tax allowance would have to establish that its partners or members have an actual or potential income tax obligation on the entity’s public utility income. The FERC has stated that it will determine on a case-by-case basis whether there is an actual or potential income tax liability. The policy appears to provide an opportunity for partnership-owned pipelines to seek allowances based upon their entire income paid to partners, rather than the partial allowance which was limited to partner interests owned by corporate partners. The policy statement is subject to rehearing and clarification by the FERC. Enterprise Products Partners has not yet been able to determine the effect, if any, that this new FERC policy statement will have on the rates for transportation services on its interstate pipelines it charges or on the rates it will be allowed to charge in the future. Enterprise Products Partners expects the implementation of the policy in individual cases will be subject to review by the United States Court of Appeals. On June 1, 2005 the FERC issued its order on remand of BP West Coast which reiterated the FERC’s position on

 

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income tax allowance as set forth in the policy statement. Applying that policy, the FERC found that SFPP should be afforded an income tax allowance on all of its partnership interests to the extent that the owners of those interests had an actual or potential income tax liability during the periods at issue. The FERC has initiated a public inquiry in Docket No. PL05-5 into the proper treatment of income tax allowances on cost-of-service ratemaking proceeding involving partnerships. Moreover, it is not clear whether FERC’s action taken in response to BP West Coast will be challenged and, if so, whether it will withstand further FERC or judicial review.

 

Regulation of Enterprise Products Partners’ Interstate and Intrastate Natural Gas Pipelines

 

The High Island Offshore System interstate natural gas pipeline, or HIOS, certain natural gas pipelines in which Enterprise Products Partners owns equity interests and the Petal natural gas storage facility, including the 60-mile Petal natural gas pipeline, are regulated by the FERC under the Natural Gas Act of 1938, or NGA, and the NGPA. Each system operates under separate FERC-approved tariffs that establish rates, terms and conditions under which each system provides services to its customers. Pursuant to FERC’s jurisdiction over interstate gas pipeline rates, existing pipeline rates may be challenged by customer complaint or by the FERC staff and proposed rate increases may be challenged by protest.

 

In December 2002, HIOS filed a rate case pursuant to Section 4 of the NGA to increase its transportation fees. FERC accepted HIOS’ new rates, subject to refund, and set certain issues for hearing. In response to the administrative law judge’s, or ALJ’s, initial decision proposing rates lower than the rate initially proposed by HIOS, HIOS filed a settlement agreement on August 5, 2004 whereby HIOS proposed to implement its rates in effect prior to this proceeding for a prospective three-year period.

 

On January 24, 2005, the FERC rejected HIOS’ settlement offer and generally affirmed the ALJ’s initial decision, resulting in rates significantly lower than the rate proposed in HIOS’ settlement offer. On February 24, 2005, Enterprise Products Partners filed a request for rehearing with the FERC. Enterprise Products Partners is not able to predict the outcome of the HIOS proceeding, but an adverse outcome in this proceeding or any other rate case proceedings to which it may be a party in the future could adversely affect its results of operations, cash flows and financial position.

 

In addition, the FERC’s authority over natural gas companies that provide natural gas pipeline transportation or storage services in interstate commerce includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the acquisition, extension, disposition or abandonment of facilities, the maintenance of accounts and records the initiation, extension and discontinuation of services, and various other matters. As noted above, its regulated natural gas pipelines and natural gas storage facility have tariffs established through FERC filings that have a variety of terms and conditions, each of which affect the operations of each system and its ability to recover fees for the services it provides. Generally, changes to these fees or terms can only be implemented upon approval by the FERC. Enterprise Products Partners also owns several natural gas intrastate systems that provide transportation and storage pursuant to Section 311 of the NGPA and Section 284 of the Commission’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. 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. The FERC has exempted the construction of facilities used solely for Section 311 transportation from the FERC’s certificate requirements.

 

In addition to its jurisdiction under the NGA and the NGPA, the FERC also attempted to use the Outer Continental Shelf Lands Act, or OCSLA, open access provisions to expand its jurisdiction over pipelines on the Outer Continental Shelf. The OCSLA requires that all pipelines operating on or across the outer continental shelf provide open-access, non-discriminatory transportation service on their systems. The U.S. Court of Appeals for the District of Columbia Circuit recently upheld a lower court’s rejection of FERC’s attempt to implement regulations pertaining to “gas service providers” operating on the outer continental shelf. The Minerals Management Service, or MMS, a bureau in the U.S. Department of the Interior, is the Federal agency that

 

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manages the nation’s natural gas, oil and other mineral resources on the outer continental shelf is also reviewing its jurisdiction with respect to the open-access, non-discriminatory provisions of the OCSLA. We cannot predict what further action the FERC or the MMS will take under its OCSLA authority.

 

In November 2003, the FERC issued final rules governing the standards of conduct between transmission providers and their energy affiliates that apply to interstate natural gas pipelines and public utilities. The rules became effective on February 9, 2004, and on or before that date, each transmission provider was required to file with the FERC a plan and schedule for implementing the new rules. The rules substantially modify the scope of the FERC’s previous standards of conduct regulations by broadening the definition of “affiliates” covered by the standards of conduct to include “energy affiliates.” The rules make each transmission provider responsible for ensuring complete separation of certain functions between itself and its “energy affiliates” and for compliance with specific information disclosure prohibitions. The rules require that transmission providers conduct training for all employees regarding the scope and content of the rules, and hire or designate a chief compliance officer who is responsible for employee training and answering employee questions regarding the new rules and coordinating audits and investigations with FERC staff, as well as ensuring that the transmission provider complies with the standards of conduct. The rules prohibit employees of a transmission provider from using any third party, affiliate or employee of an affiliate as a conduit for sharing information that is prohibited under the rules from disclosure to energy affiliates.

 

On April 16, 2004 and August 2, 2004, the FERC issued Orders on rehearing regarding certain aspects of Order No. 2004. Those rehearing orders were issued as Order No. 2004-A and 2004-B, respectively. Among other things, FERC ruled that the final rule was needed and extended the compliance date to September 22, 2004. On July 27, 2004, GulfTerra filed a request for temporary limited waivers of certain requirements of the Standards of Conduct. The requested waivers were necessary because of its merger with Enterprise Products Partners. GulfTerra requested that the FERC grant limited waivers of compliance for those aspects of the Standards of Conduct that could not be fully addressed until after the merger was consummated. The waiver request was for a period of 45 days after the merger. The FERC granted a 30 day extension after the merger was complete to comply. October 30, 2004 was the date for compliance. On December 21, 2004, the FERC issued Order No. 2004-C which clarified certain aspects of the Order. We believe compliance with this final rule should not be unduly burdensome on Enterprise Products Partners.

 

Regulation of Enterprise Products Partners’ intrastate common carrier liquids and natural gas pipelines

 

Enterprise Products Partners’ intrastate NGL and natural gas pipelines are subject to regulation in Alabama, Colorado, Kansas, Illinois, Louisiana, Mississippi, New Mexico and Texas and some of its intrastate natural gas pipelines are subject to regulation by the FERC pursuant to Section 311 of the NGPA. Certain portions of the Louisiana Pipeline System and the majority of the Acadian Gas natural gas pipeline systems are intrastate common carrier pipelines that are subject to various Louisiana state laws and regulations that affect the rates Enterprise Products Partners charges and the terms of service. The Texas Intrastate System and the Alabama Intrastate System are subject to state laws and regulations in Texas and Alabama and to FERC regulation under Section 311 of the NGPA. Enterprise Products Partners also has natural gas underground storage facilities in Louisiana, Mississippi and Texas that are subject to state regulations.

 

Intrastate movements of products on the Seminole, Mid-America, Belle Rose and certain pipelines of the Louisiana Pipeline System are provided by them as intrastate common carriers that are subject to various other state laws and regulations that affect the rates Enterprise Products Partners charges and the terms of service. Although state regulation is typically less onerous than FERC regulation, proposed and existing rates subject to state regulation and the provision of services on a non-discriminatory basis are also subject to challenge by protest and complaint, respectively.

 

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Other state and local regulation of its operations

 

Enterprise Products Partners’ business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters.

 

For additional information regarding the potential impact of federal, state or local regulatory measures on Enterprise Products Partners’ business, please read “Risk Factors.”

 

Environmental Matters

 

General Regulations

 

Enterprise Products Partners is subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations may, in certain instances, require Enterprise Products Partners to remedy the effects on the environment of the disposal or release of specified substances at current and former operating sites.

 

Enterprise Products Partners 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 Enterprise Products Partners to reassess its potential exposure related to environmental matters. As this information becomes available, or other relevant developments occur, Enterprise Products Partners will make accruals accordingly. For a summary of Enterprise Products Partners’ significant environmental-related accruals, please read the Note 1 of the Notes to Consolidated Financial Statements of Enterprise Products GP included elsewhere in this prospectus.

 

Enterprise Products Partners’ offshore pipelines and services are subject to various safety and environmental statutes, including: the OCSLA, the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the Oil Pollution Act of 1990, the Endangered Species Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act and similar state statutes. Enterprise Products Partners has ongoing programs designed to keep its oil and natural gas pipelines and offshore platform operations in compliance with environmental and safety requirements, and Enterprise Products Partners believes that its facilities are in material compliance with the applicable requirements.

 

Enterprise Products Partners’ onshore natural gas pipelines, gas processing and treating plants and storage facilities are subject to various safety and environmental statutes, including: the Natural Gas Act, the Natural Gas Policy Act, the Hazardous Materials Transportation Act, the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the Oil Pollution Act of 1990, the Endangered Species Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act and similar state statutes. Enterprise Products Partners has ongoing programs designed to keep its natural gas pipelines and gas processing plants in compliance with environmental and safety requirements, and Enterprise Products Partners believes that its facilities are in material compliance with the applicable requirements. As of December 31, 2004, Enterprise Products Partners had a reserve of approximately $21 million, included in other noncurrent liabilities, for environmental remediation costs expected to be incurred over time associated with mercury meters. GulfTerra assumed this liability in connection with its April 2002 acquisition of certain El Paso Corporation assets.

 

Enterprise Products Partners’ NGL pipelines and services are subject to various safety and environmental statutes, including: the Hazardous Materials Transportation Act, the Hazardous Liquid Pipeline Safety Act, the

 

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Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the Oil Pollution Act of 1990, the Endangered Species Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act and similar state statutes. Enterprise Products Partners has ongoing programs designed to keep its NGL pipelines and NGL fractionation, NGL storage and petrochemical storage operations in compliance with environmental and safety requirements, and Enterprise Products Partners believes that its facilities are in material compliance with the applicable requirements.

 

Enterprise Products Partners’ petrochemical services operations are subject to various safety and environmental statutes, including: the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the Endangered Species Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act, and similar state statutes. Enterprise Products Partners has ongoing programs designed to keep its storage operations in compliance with environmental and safety regulations, and Enterprise Products Partners believes that its facilities are in material compliance with the applicable requirements.

 

Specific Regulations

 

Pipelines . Several federal and state environmental statutes and regulations may pertain specifically to the operations of its 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.

 

Solid Waste . The operations of its pipelines and plants 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 Enterprise Products Partners.

 

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 EPA 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 natural gas, Enterprise Products Partners may nonetheless handle “hazardous substances,” within the meaning of CERCLA or similar state statutes, in the course of its ordinary operations.

 

Air . Enterprise Products Partners’ operations may be subject to the Clean Air Act, or CAA, 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. Enterprise Products Partners may be required to incur certain capital expenditures in the next several

 

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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 Enterprise Products Partners’ operations will be materially adversely affected by any such requirements.

 

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.

 

Communication of Hazards . The Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act and comparable state statutes require those entities that operate facilities for Enterprise Products Partners 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.

 

Title to Properties

 

Enterprise Products Partners’ real property holdings fall into two basic categories: (1) parcels that Enterprise Products Partners owns in fee, such as the land at the Mont Belvieu complex and (2) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for its operations. The fee sites upon which its major facilities are located have been owned by Enterprise Products Partners or its 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 Enterprise Products Partners has 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 it or to its title to any material lease, easement, right-of-way, permit or license, and we believe that Enterprise Products Partners has satisfactory title to all of its material leases, easements, rights-of-way and licenses.

 

A significant portion of the rights-of-way underlying the San Juan gathering system on Native American lands expire in 2005. We believe Enterprise Products Partners will be able to renew these rights-of-way on terms and conditions that will not be materially adverse to it.

 

Legal Proceedings

 

On occasion, Enterprise Products Partners is named as a defendant in litigation relating to its normal business operations, including regulatory and environmental matters. Although Enterprise Products Partners is 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 Enterprise Products Partners against liabilities arising from future legal proceedings as a result of its ordinary business activity. We are not aware of any significant litigation, pending or threatened, that may have a material adverse effect on our or Enterprise Products Partners’ financial position or results of operations.

 

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MANAGEMENT

 

General

 

As is commonly the case with publicly traded limited partnerships, we will not directly employ any of the persons responsible for the management or operations of our business, including the executive officers of our general partner and key management personnel. These functions will be performed by the employees of EPCO pursuant to an administrative services agreement under the direction of the board of directors and executive officers of EPE Holdings, LLC, our general partner.

 

Notwithstanding any contractual limitation on its obligations or duties, our general partner will be 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.

 

Governance Matters

 

Independence of Board Members . Our general partner is committed to having at least a majority of its board of directors be independent 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 our general partner or us). The board of directors of our general partner has nominated and will appoint two independent members prior to the listing of our units. In compliance with the corporate governance rules of the NYSE, the board of directors of our general partner will appoint a third independent member within twelve months of listing. The independent members of the board of directors of our general partner will serve as the initial members of the audit and conflicts and governance committees.

 

Heightened Independence for Audit and Conflicts Committee Members . As required by the Sarbanes-Oxley Act of 2002, the Commission has 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. The board of directors of our general partner expects that all members of its audit and conflicts committee will 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, Commission 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, possesses 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;

 

    An understanding of internal controls and procedures for financial reporting; and

 

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    An understanding of audit committee functions.

 

The board of directors of our general partner expects that one of the independent directors will satisfy the definition of “audit committee financial expert.”

 

Executive Sessions of Board . The board of directors of our general partner will hold 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.

 

In accordance with the rules of the NYSE, we have designated our toll-free, confidential hotline as the method for interested parties to communicate with the presiding director, alone, or with the non-management directors of our general partner as a group. All calls to this hotline are reported to the chairman of the audit and conflicts committee of our general partner, who is responsible for communicating any necessary information to the other non-management directors as a group. The number of our confidential hotline is 1-877-888-0002. The hotline is operated by The Network is an independent contractor that specializes in providing feedback/reporting services to more than 1,000 companies in a variety of industries.

 

Committees of Board of Directors . The board of directors of our general partner will initially establish two committees: an audit and conflicts committee and a governance committee. In accordance with NYSE rules and Section 3(a)(58)(A) of the Securities Exchange Act of 1934, the board of directors of our general partner will name three of its members to serve on its audit and conflicts committee. The members of the audit and conflicts committee will be independent directors, free from any relationship with us or any of our affiliates that would interfere with the exercise of independent judgment.

 

Members of the audit and conflicts committee must have a basic understanding of finance and accounting and be able to read and understand fundamental financial statements, and at least one member of the committee must have accounting or related financial management expertise. The primary responsibilities of the audit and conflicts committee will include:

 

    monitoring the integrity of our financial reporting process and related systems of internal control;

 

    ensuring our legal and regulatory compliance and that of our general partner;

 

    overseeing the independence and performance of our independent public accountants;

 

    approving all services performed by our independent public accountants;

 

    providing for an avenue of communication among the independent public accountants, management, internal audit function and the board of directors of our general partner;

 

    encouraging adherence to and continuous improvement of our policies, procedures and practices at all levels; and

 

    reviewing areas of potential significant financial risk to our businesses.

 

The audit and conflicts committee also will have the authority to review specific matters as to which the board of directors of our general partner believes there may be a conflict of interests in order to determine if the resolution of such conflict proposed by our general partner is fair and reasonable to us. Any matters approved by the audit and conflicts committee are conclusively deemed to be fair and reasonable to our business, approved by all of our partners and not a breach by our general partner or its board of directors of any duties they may owe us or our unitholders.

 

Pursuant to a formal written charter to be adopted prior to the closing of this offering, the audit and conflicts committee will have the authority to conduct any investigation appropriate to fulfilling its responsibilities, and it will have direct access to our independent public accountants as well as any EPCO personnel it deems necessary

 

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in fulfilling its responsibilities. The audit and conflicts committee will also have the ability to retain, at our expense, special legal, accounting or other consultants or experts it deems necessary in the performance of its duties.

 

In addition to the audit and conflicts committee, the board of directors of our general partner will establish a governance committee. The governance committee will be appointed by the board of directors of our general partner to assist the board in fulfilling its oversight responsibilities. The governance committee’s primary duties and responsibilities will be to develop and recommend to the board of directors of our general partner a set of governance principles applicable to us and communicate with members of the board regarding board meeting format and procedures.

 

Governance Guidelines . Governance guidelines, together with committee charters, provide the framework for effective governance. The board of directors of our general partner will adopt the Enterprise GP Holdings governance guidelines addressing several matters, including qualifications for directors, responsibilities of directors, retirement of directors, the composition and responsibility of committees, the conduct and frequency of board and committee meetings, management succession, director access to management and outside advisors, director compensation, director orientation and continuing education, and annual self-evaluation of the board. The board of directors of our general partner recognizes that effective governance is an on-going process, and thus, the board will review the Enterprise GP Holdings governance guidelines annually or more often as deemed necessary.

 

Code of Ethics . The board of directors of our general partner will adopt a code of ethics, the “Code of Ethical Conduct for Senior Financial Officers and Managers,” that applies to the chief executive officer, chief financial officer, principal accounting officer and senior financial and other managers. In addition to other matters, this code of ethics establishes policies to prevent wrongdoing and to promote honest and ethical conduct, including ethical handling of actual and apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting violations of the code.

 

Web Access . We will provide access through our website at www.enterprisegp.com to current information relating to governance, including a copy of each board committee charter, the Code of Ethical Conduct for Senior Financial Officers and Managers, the Enterprise GP Holdings governance guidelines and other matters impacting our governance principles. You may also contact our investor relations department for paper copies of these documents free of charge.

 

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Enterprise GP Holdings

 

Directors and Officers of Our General Partner

 

The following table sets forth certain information with respect to the executive officers, members of the board of directors of our general partner, EPE Holdings, LLC, and nominees to be named members of our general partner’s board of directors prior to the listing of our units. Each member of the board of directors of our general partner serves until such member’s death, resignation or removal. The executive officers are elected for one-year terms and may be removed, with or without cause, only by the board of directors of the general partner. Our unitholders do not elect the officers or directors of our general partner. Dan L. Duncan, through his control of Dan Duncan LLC, the sole member of our general partner, has the ability to elect, remove and replace at any time, all of the officers and directors of our general partner.

 

Name


   Age

  

Position with EPE Holdings, LLC


Dan L. Duncan (1)

   72    Director and Chairman

Michael A. Creel (1)

   51    Director, President and Chief Executive Officer

Richard H. Bachmann (1)

   52    Executive Vice President, Chief Legal Officer and Secretary

W. Randall Fowler (1)

   48    Senior Vice President and Chief Financial Officer

Michael J. Knesek (1)

   51   

Senior Vice President, Controller and Principal Accounting Officer

Charles E. McMahen(2)

   66    Director nominee

Edwin E. Smith(2)

   73    Director nominee

(1) Executive officer
(2) Member of audit and conflicts committee

 

All of our general partner’s executive officers will, and certain of the other EPCO employees assigned to our operations may, also perform services for EPCO, Enterprise Products Partners and TEPPCO Partners and their affiliates. The services performed by these shared personnel generally will be limited to non-commercial and administrative functions, including but not limited to human resources, information technology, financial and accounting services and legal services. Policies and procedures have been established to protect and prevent inappropriate disclosure by shared personnel of commercial and other non-public information relating to us, Enterprise Products Partners and TEPPCO Partners. Since our general partner’s executive officers allocate time among EPCO, us, Enterprise Products Partners and TEPPCO Partners, these officers face conflicts regarding the allocation of their time, which may adversely affect our Enterprise Products Partners’ business, results of operations and financial condition.

 

Dan L. Duncan was elected Chairman and Director of our general partner in April 2005 and Chairman and a Director of Enterprise Products GP in April 1998. Mr. Duncan has served as Chairman of EPCO since 1979.

 

Michael A. Creel was elected President, Chief Executive Officer and Director of our general partner in April 2005 and elected an Executive Vice President, Chief Financial Officer of Enterprise Products GP and EPCO in January 2001, having served as a Senior Vice President of Enterprise Products GP and EPCO since November 1999. In June 2000, Mr. Creel, a certified public accountant, was elected Chief Financial Officer of Enterprise Products GP and EPCO.

 

Richard H. Bachmann was elected Executive Vice President, Chief Legal Officer and Secretary of our general partner in April 2005 and Executive Vice President, Chief Legal Officer and Secretary of Enterprise Products GP and EPCO in January 1999. Mr. Bachmann served as a Director of Enterprise Products GP from June 2000 to January 2004.

 

W. Randall Fowler was elected Senior Vice President and Chief Financial Officer of our general partner in April 2005 and joined Enterprise Products Partners as director of investor relations in January 1999. Mr. Fowler, a certified public accountant (inactive), was elected to the positions of Treasurer and a Vice President of

 

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Enterprise Products GP and EPCO in August 2000 and Senior Vice President and Treasurer of Enterprise Products GP and EPCO in February 2005.

 

Michael J. Knesek was elected Senior Vice President, Controller and Principal Accounting Officer of our general partner in April 2005 and Senior Vice President, Controller and Principal Accounting Officer of Enterprise Products GP and EPCO in February 2005, having served as Vice President, Controller and Principal Accounting Officer since August 2000. Since 1990, Mr. Knesek, a certified public accountant, has been the Controller and a Vice President of EPCO.

 

Charles E. McMahen has been nominated to be a member of our general partner’s board of directors. Mr. McMahen served as Vice Chairman of Compass Bank from March 1999 until December 2003 and served as Vice Chairman of Compass Bancshares from April 2001 until his retirement in December 2003. Mr. McMahen also served as Chairman and Chief Executive Officer of Compass Banks of Texas from March 1990 until March 1999. Mr. McMahen was named to the Board of Directors of Compass Bancshares, Inc. in 2001 and remains a director of Compass Bancshares, Inc. Mr. McMahen is also a director and a member of the audit and finance committee of PNM Resources, Inc., a publicly traded company. Mr. McMahen served on the Board of Directors and Executive Committee of the Greater Houston Partnership from 1995 to 2003. He served as Chairman of the Board of Regents of the University of Houston from September 1998 to August 2000. Mr. McMahen will serve as a member of our general partner’s audit and conflicts committee.

 

Edwin E. Smith has been nominated to be a member of our general partner’s board of directors. Mr. Smith has been a private investor since he retired from Allied Bank of Texas in 1989 after a 31-year career in banking. Mr. Smith serves as a director of Encore Bank and previously served as a director of EPCO, Inc. (formerly Enterprise Products Company) from 1987 until 1997. Mr. Smith will serve as a member of our general partner’s audit and conflicts committee.

 

Compensation of Directors . Neither we nor our general partner will provide any additional compensation to employees of EPCO who serve as directors of our general partner. The employees of EPCO who will initially serve as directors of our general partner are Mr. Duncan and Mr. Creel.

 

The independent outside directors of our general partner will be compensated for their services at the expense of EPE Holdings, LLC. We expect that the compensation arrangements for these independent directors will initially be as follows: (i) an annual retainer of $25,000 in cash and $25,000 worth of restricted common units and (ii) an annual retainer of $7,500 in cash for serving as chairman of a committee of the board of directors of our general partner.

 

Executive Officer Compensation

 

Employee Partnership

 

Prior to the closing of this offering, EPCO Holdings Inc., a wholly owned subsidiary of EPCO, will form a Delaware limited partnership, EPE Unit L.P., which we refer to as the employee partnership. EPCO Holdings will serve as the general partner of the employee partnership. In connection with the closing of this offering, EPCO Holdings will borrow $51 million under its credit facility, under which affiliates of certain underwriters in this offering will be lenders, to purchase an estimated 1,888,889 units from us at the initial public offering price. EPCO Holdings will contribute the purchased units but not the related debt to the employee partnership. In connection with the closing of this offering, certain EPCO employees, including all of our general partner’s executive officers other than the Chairman, will be issued limited partner interests without any capital contribution and be admitted as limited partners of the employee partnership.

 

Unless otherwise agreed to by EPCO Holdings and a majority in interest of the limited partners of the employee partnership, the employee partnership will terminate at the earlier of five years following the closing of

 

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this offering or a change in control of us or our general partner. The employee partnership will have the following material terms with respect to distributions:

 

    Distributions of Cashflow —each quarter, 100% of the distributions from our units will be distributed to EPCO Holdings until it has received the general partner’s preferred return (as defined below), and any remaining distributions from the employee partnership will be distributed to the limited partners. The general partner’s preferred return will equal (i) 1.5625% per quarter, or 6.25% per annum, of the general partner’s capital base, plus (ii) any unpaid general partner’s preferred return from prior periods. The general partner’s capital base will equal the value of the units contributed to the employee partnership by EPCO Holdings as of the time of contribution, increased by any unpaid general partner preferred return from prior periods, and decreased by any distributions of sale proceeds to EPCO Holdings as described below.

 

    Liquidating Distributions —Upon liquidation of the employee partnership, units having a fair market value equal to the general partner’s capital base will be distributed to EPCO Holdings, plus any accrued general partner’s preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the limited partners.

 

    Sale Proceeds —If the employee partnership sells any units, the sale proceeds will be distributed to EPCO Holdings and the limited partners in the same manner as liquidating distributions described above. The employee partnership does not intend to sell any units until the termination of the employee partnership at the end of five years.

 

The limited partner interests in the employee partnership that are owned by EPCO employees will be subject to forfeiture if the participating employee leaves EPCO and its affiliates prior to the fifth anniversary of the closing of this offering with customary exceptions for death, disability and certain retirements. The risk of forfeiture associated with the limited partnership interests in the employee partnership will also lapse upon certain change of control events.

 

None of us, our general partner, Enterprise Products Partners or Enterprise Products GP will reimburse EPCO Holdings, the employee partnership or any of their affiliates or partners, through the administrative services agreement or otherwise, for any expenses related to the employee partnership or the purchase of the units by EPCO Holdings for contribution to the employee partnership.

 

Long-Term Incentive Plan

 

Prior to the closing of this offering, EPCO and our current partners will adopt the 2005 EPE Long-Term Incentive Plan, which we refer to as the 2005 Plan. The 2005 Plan is intended to promote the interests of us, our general partner and EPCO by encouraging employees and directors of EPCO and its affiliates who perform services for us or our general partner to acquire or increase their equity interests in us and to provide a means whereby they may develop a sense of proprietorship and personal involvement in our development and financial success through the award of unit options, restricted units and phantom units. The 2005 Plan was developed to encourage recipients of equity awards under the plan to remain with Enterprise GP Holdings and to devote their best efforts to our business.

 

The 2005 Plan will be governed by our general partner’s board of directors or a committee appointed by the board, whose significant powers include, but are not limited to, (i) designating participants in the plan; (ii) determining the type of equity awards to be granted to a participant; (iii) determining the number of units to be covered by the equity awards; (iv) determine the terms and conditions of any equity award; and (v) determining, whether, to what extent, and under what circumstances participants may settle, exercise, cancel or forfeit any equity award. Subject to adjustment as provided in the 2005 Plan documents, the aggregate number of our units that may be awarded to participants is 250,000. Awards may be made in the form of restricted units, phantom units or options to purchase units. It is currently intended that awards under this plan will be limited to restricted units or phantom units which will be awarded to the independent directors of our general partner as

 

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compensation, the cost of which will be borne by our general partner. Please read “—Directors and Officers of Our General Partner—Compensation of Directors”. The units to be awarded under this plan may be obtained through purchases made on the open market, from affiliates of EPCO or from us.

 

The exercise price of unit options to be issued under the 2005 Plan, if any, will be determined by the board (or committee) at its discretion at the date of grant, but may not be less than its fair market value as of the date of grant. The committee will determine the time or times at which the awards may be exercised in whole or in part, and the method or methods by which any payment of the exercise price with respect thereto may be made or deemed to have been made, which may include cash, notes receivable from the participant, or cashless-broker transactions or other acceptable forms of payment.

 

The 2005 Plan will be effective from the date of its approval until the earliest of all available units under the plan having been issued to participants, the termination of the plan by our board of directors or the tenth anniversary of the date of approval of the plan.

 

Enterprise Products Partners

 

Directors and Executive Officers of Enterprise Products GP

 

The following table sets forth certain information with respect to the executive officers and members of the board of directors of Enterprise Products GP as of July 15, 2005. Each member of the board of directors of Enterprise Products GP serves until such member’s death, resignation or removal. The executive officers are elected for one-year terms and may be removed, with or without cause, only by the board of directors of Enterprise Products GP. Enterprise Products Partners’ unitholders do not elect the officers or directors of Enterprise Products GP. Dan L. Duncan, through his indirect control of Enterprise Products GP, has the ability to elect, remove and replace at any time, all of the officers and directors of Enterprise Products GP.

 

Name


   Age

  

Position with Enterprise Products GP


Dan L. Duncan (1)(2)

   72    Non-Voting Director and Chairman

O.S. Andras

   69    Director

Robert G. Phillips (1)

   50    Director, President and Chief Executive Officer

E. William Barnett (3)(4)

   72    Director

W. Matt Ralls (3)(4)

   56    Director

Richard S. Snell (3)(4)

   63    Director

Richard H. Bachmann (1)

   52    Executive Vice President, Chief Legal Officer and Secretary

Michael A. Creel (1)

   51    Executive Vice President and Chief Financial Officer

James H. Lytal (1)

   47    Executive Vice President

A.J. Teague (1)

   60    Executive Vice President

Charles E. Crain (1)

   71    Senior Vice President

William Ordemann (1)

   46    Senior Vice President

Gil H. Radtke (1)

   44    Senior Vice President

James M. Collingsworth (1)

   50    Senior Vice President

James A. Cisarik (1)

   47    Senior Vice President

Lynn L. Bourdon, III (1)

   43    Senior Vice President

Bart H. Heijermans (1)

   38    Senior Vice President

Richard A. Hoover (1)

   48    Senior Vice President

Joel D. Moxley (1)

   47    Senior Vice President

Michael J. Knesek (1)

   51    Senior Vice President, Controller and Principal Accounting Officer

W. Randall Fowler (1)

   48    Senior Vice President and Treasurer

(1) Executive officer
(2) Mr. Duncan is currently a non-voting director of Enterprise Products GP. Until a fourth independent director is appointed to Enterprise Products GP’s board, Mr. Duncan will remain a non-voting director to preserve the voting majority of the independent directors.
(3) Member of audit and conflicts committee
(4) Member of governance committee

 

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As described above, some of the directors and executive officers of our general partner, EPE Holdings, LLC also serve as directors and executive officers of Enterprise Products GP. To the extent that we have described the business experience of these individuals above, we have not repeated that information below.

 

O.S. Andras served as Vice Chairman and Director of Enterprise Products GP from February 11, 2005 to June 30, 2005, prior to which he had been Chief Executive Officer, Vice Chairman and a Director of Enterprise Products GP from September 30, 2004 to February 11, 2005. Mr. Andras served as President, Chief Executive Officer and a Director of Enterprise Products GP from April 1998 until September 30, 2004. Mr. Andras served as President and Chief Executive Officer of EPCO from 1996 to February 2001 and has served as Vice Chairman of EPCO from January 2001 to June 2005. Mr. Andras retired as Vice Chairman of Enterprise Products GP effective July 1, 2005 but continues to serve as a non-executive director.

 

Robert G. Phillips has served as President, Chief Executive Officer and Director of Enterprise Products GP since February 11, 2005. He served as President, Chief Operating Officer and a Director of Enterprise Products GP beginning on September 30, 2004, which was the date of completion of the GulfTerra merger. Enterprise Products Partners agreed to elect Mr. Phillips to those positions in connection with negotiating the GulfTerra merger agreement. Mr. Phillips served as a Director of GulfTerra’s general partner from August 1998 until September 2004. In addition, he served as Chief Executive Officer for GulfTerra and its general partner from November 1999 and as Chairman from October 2002 until September 2004. He served as Executive Vice President of GulfTerra from August 1998 to October 1999. Mr. Phillips served as President of El Paso Field Services Company between June 1997 and September 2004. He served as President of El Paso Energy Resources Company from December 1996 to July 1997, President of El Paso Field Services Company from April 1996 to December 1996 and Senior Vice President of El Paso Corporation from September 1995 to April 1996. For more than five years prior thereto, Mr. Phillips was Chief Executive Officer of Eastex Energy, Inc.

 

E. William Barnett was elected a Director of Enterprise Products GP in March 2005. Mr. Barnett practiced law with Baker Botts L.L.P. from 1958 until his retirement in 2004. In 1984, he became Managing Partner of Baker Botts L.L.P. and continued in that role for 14 years until 1998. He was Senior Counsel to the firm from 1998 until June 1, 2004 when he retired from the firm. Mr. Barnett is Chairman of the Board of Trustees of Rice University; a Life Trustee of The University of Texas Law School Foundation; a director of St. Luke’s Episcopal Health System and a current director and former Chairman of the Board of Directors of the Houston Zoo, Inc. (the operating arm of the Houston Zoo). He is a director of Reliant Energy, Inc., a publicly traded electric services company. He is also a director and former Chairman of the Greater Houston Partnership. He also served as a trustee of Baylor College of Medicine from 1993 until 2004. Mr. Barnett is a member of Enterprise Products GP’s audit and conflicts committee and serves as chairman of its governance committee.

 

W. Matt Ralls was elected a Director of Enterprise Products GP in September 2004. Mr. Ralls served as a Director of GulfTerra’s general partner from May 2003 to September 2004. Mr. Ralls served as Senior Vice President and Chief Financial Officer of GlobalSantaFe, an international contract drilling company, from 2001 to June 2005 and was elected Executive Vice President and Chief Operating Officer of GlobalSantaFe in June 2005. From 1997 to 2001, he was Vice President, Chief Financial Officer and Treasurer of Global Marine, Inc. Previously, he served as Executive Vice President, Chief Financial Officer and Director of Kelly Oil and Gas Corporation and as Vice President of Capitals Markets and Corporate Development for the Meridian Resource Corporation before joining Global Marine. He spent the first 17 years of his career in commercial banking, ultimately serving at the senior management level. Mr. Ralls serves as chairman of Enterprise Products GP’s audit and conflicts committee and is a member of its governance committee.

 

Richard S. Snell was elected a Director of Enterprise Products GP in June 2000. Mr. Snell was an attorney with the Snell & Smith, P.C. law firm in Houston, Texas from the founding of the firm in 1993 until May 2000. Since May 2000, he has been a partner with the firm of Thompson & Knight LLP in Houston, Texas, and he is a

 

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certified public accountant. Mr. Snell is a member of Enterprise Products GP’s governance committee. Mr. Snell is a member of Enterprise Products GP’s audit and conflicts committee and is a member of its governance committee.

 

James H . Lytal was elected Executive Vice President of Enterprise Products GP in September 2004. Mr. Lytal served as a Director of GulfTerra’s general partner from August 1994 until September 2004, and as GulfTerra’s President and President of GulfTerra’s general partner from July 1995 until September 2004. He served as Senior Vice President of GulfTerra and its general partner from August 1994 to June 1995. Prior to joining GulfTerra, Mr. Lytal served in various capacities in the oil and gas exploration and production and gas pipeline industries with Untied Gas Pipeline Company, Texas Oil and Gas, Inc. and American Pipeline.

 

A.J. Teague was elected an Executive Vice President of Enterprise Products GP in November 1999. From 1998 to 1999 he served as President of Tejas Natural Gas Liquids, LLC, then a Shell affiliate.

 

Charles E. Crain was elected a Senior Vice President of Enterprise Products GP in April 1998. Mr. Crain served as Senior Vice President of Operations for EPCO from 1991 to 1998.

 

William Ordemann joined Enterprise Products Partners as a Vice President of Enterprise Products GP in October 1999 and was elected a Senior Vice President in September 2001. From January 1997 to February 1998, Mr. Ordemann was a Vice President of Shell Midstream Enterprises, LLC, and from February 1998 to September 1999 was a Vice President of Tejas Natural Gas Liquids, LLC, both Shell affiliates.

 

Gil H. Radtke was elected a Senior Vice President of Enterprise Products GP in February 2002. Mr. Radtke joined Enterprise Products Partners in connection with its purchase of Diamond-Koch’s storage and propylene fractionation assets in January and February 2002. Before joining Enterprise Products Partners, Mr. Radtke served as President of the Diamond-Koch joint venture from 1999 to 2002, where he was responsible for its storage, propylene fractionation, pipeline and NGL fractionation businesses. From 1997 to 1999 he was Vice President, Petrochemicals and Storage of Diamond-Koch.

 

James M. Collingsworth joined Enterprise Products GP as a Vice President in November 2001 and was elected a Senior Vice President in November 2002. Previously, he served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991 to 2001 in various management positions, including Senior Vice President of NGL Assets and Business Services from July 1998 to October 2001.

 

James A. Cisarik was elected a Senior Vice President of Enterprise Products GP in February 2003. Mr. Cisarik joined Enterprise Products Partners in April 2001 when it acquired Acadian Gas from Shell. His primary responsibility since joining Enterprise Products Partners has been oversight of the commercial activities of its natural gas businesses, principally those of Acadian Gas and its Gulf of Mexico natural gas pipeline investments. From February 1999 through March 2001, Mr. Cisarik was a Senior Vice President of Coral Energy, LLC. and from 1997 to February 1999 was Vice President, Market Development of Tejas Energy, LLC, both affiliates of Shell, with responsibilities in market development for their Texas and Louisiana natural gas pipeline systems.

 

Lynn L. Bourdon, III , was elected a Senior Vice President of Enterprise Products GP on December 10, 2003. His primary responsibility since joining Enterprise Products Partners has been oversight of all NGL supply and marketing functions. Previously, Mr. Bourdon served as Senior Vice President and Chief Commercial Officer of Orion Refining Corporation from July 2001 through November 2003. Orion Refining Corporation filed for protection under U.S. Federal bankruptcy laws in May 2003. Mr. Bourdon was a shareholder in En*Vantage, Inc., a business investment and energy services company serving the petrochemicals and energy industries, from September 1999 through July 2001. He also served as a Senior Vice President of PG&E Corporation for gas transmission commercial operations from August 1997 through August 1999.

 

Bart H. Heijermans was elected Senior Vice President of Enterprise Products GP in September 2004. Mr. Heijermans served as GulfTerra’s Vice President, Offshore from June 2003 until September 2004. From June

 

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2001 to June 2003, he served as GulfTerra’s Vice President, Deepwater Project Development. He served as GulfTerra’s Vice President, Operations and Engineering from August 1997 to June 2001. Prior to joining GulfTerra, Mr. Heijermans served in various capacities in the development and construction of offshore oil and gas infrastructure for Shell E&P International and Shell Research in The Netherlands, the United Kingdom and the U.S.

 

Richard A. Hoover was elected Senior Vice President of Enterprise Products GP in September 2004. Mr. Hoover served as GulfTerra’s Vice President Western Division – Commercial from January 2001 until September 2004. This position included management of GulfTerra’s San Juan and Permian Basin assets. Mr. Hoover has held various other commercial positions since joining GulfTerra in June 1996, including management of assets in the Texas Gulf Coast, Anadarko Basin, Mid Continent and Rockies. Prior to joining GulfTerra, Mr. Hoover held various positions over 16 years in the Midstream, Independent Power and E&P sectors with Delhi Pipeline Corporation, Panda Energy Corporation and Champlin Petroleum Corporation.

 

Joel D. Moxley was elected Senior Vice President of Enterprise Products GP in September 2004. Mr. Moxley served as GulfTerra’s Vice President, Processing and NGL Marketing from December 2000 until September 2004. From August 1997 to December 2000, Mr. Moxley was a Vice President at PG&E Gas Transmission-Texas where he had responsibilities for gas processing, supply and NGL marketing. Mr. Moxley held various positions with natural gas, gas processing and business development operations at Valero Energy Corporation from July 1991 to July 1997. He spent the first 11 years of his career at Occidental Petroleum where he served in various engineering, operations, marketing and business development positions within the gas processing division.

 

Executive Compensation

 

Enterprise Products Partners does not directly employ any of the persons responsible for managing or operating its business. Instead, it is managed by Enterprise Products GP, the executive officers of which are employees of, and the compensation of whom is paid by, EPCO. Enterprise Products Partners’ reimbursement to EPCO for these costs is governed by an administrative services agreement.

 

Summary Compensation Table . The following table sets forth certain compensation information for the years ended December 31, 2004, 2003 and 2002, with respect to Enterprise Products GP’s chief executive officer and the four other most highly compensated executive officers in 2004 (the named executive officers).

 

Name and Principal

Position with Enterprise

Products GP

during 2004


                  Long-term Compensation Awards

    
        Annual Compensation

  

Restricted

Unit

Awards ($) (1)


   

Securities

Underlying

Options (#)


  

All Other

Compensation (2)


   Year

   Salary

   Bonus

       

O.S. Andras

   2004    $ 798,000                        $ 10,997

Chief Executive Officer (3)

   2003      877,800                          11,865
     2002      864,000                          13,671

A.J. Teague

   2004      392,500    $ 50,000    $ 251,400 (4)   35,000      22,947

Executive Vice President

   2003      381,280      80,000                   20,583
     2002      370,000      70,000                   17,240

Charles E. Crain

   2004      267,000      50,000      621,667 (5)   25,000      20,698

Senior Vice President

   2003      250,500      50,000                   20,348
     2002      240,000      50,000                   17,089

James H. Collingsworth

   2004      260,000      50,000      125,700 (6)   25,000      19,208

Senior Vice President

   2003      206,250      50,000                   17,465
     2002      181,250                          76,882

W. Ordemann

   2004      242,500      50,000      125,700 (7)   25,000      14,968

Senior Vice President

   2003      209,917      50,000                   14,468
     2002      209,000      60,000                   14,398

 

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(1) The dollar value of restricted common unit awards to the named executive officers is calculated by multiplying the number of restricted unit awards by the closing price of Enterprise Products Partners’ unrestricted common units on the date of each grant.
(2) These amounts primarily represent contributions made by EPCO to the 401(K) plan and the employee unit purchase plan of the named executive officers.
(3) Mr. Andras served as chief executive officer of Enterprise Products GP from April 1998 to February 11, 2005, at which time Robert G. Phillips assumed the role of chief executive officer of Enterprise Products GP.
(4) At December 31, 2004, Mr. Teague held 12,000 restricted common units valued at $310,320 based on a closing price of $25.86 per unit for Enterprise Products Partners’ unrestricted common units on that date.
(5) At December 31, 2004, Mr. Crain held 27,277 restricted common units valued at $705,383 based on a closing price of $25.86 per unit for Enterprise Products Partners’ unrestricted common units on that date.
(6) At December 31, 2004, Mr. Collingsworth held 6,000 restricted common units valued at $155,160 based on a closing price of $25.86 per unit for Enterprise Products Partners’ unrestricted common units on that date.
(7) At December 31, 2004, Mr. Ordemann held 6,000 restricted common units valued at $155,160 based on a closing price of $25.86 per unit for Enterprise Products Partners’ unrestricted common units on that date.

 

Common Unit Option Grants to Named Executive Officers During 2004 . The following table provides information concerning grants of options to purchase Enterprise Products Partners’ common units by Enterprise Products GP’s audit and conflicts committee to each of the named executive officers during 2004. Mr. Andras did not receive any grants of options during 2004.

 

Name


   Number of
Securities
Underlying
Options
Granted (#)


   Individual Grants
Percent of Total
Options Granted to
EPCO Employees
in 2004


   

Exercise
Price

($/Unit)


   Expiration
Date


  

Potential Realizable

Value at Assumed

Annual Rates of Unit

Price Appreciation

for Option Term (1)


              5% ($)

   10% ($)

A. J. Teague

   35,000    3.85 %   $ 20.00    May 2014    $ 440,300    $ 1,115,450

Charles E. Crain

   25,000    2.75 %   $ 20.00    May 2014      314,500      796,750

James H. Collingsworth

   25,000    2.75 %   $ 20.00    May 2014      314,500      796,750

W. Ordemann

   25,000    2.75 %   $ 20.00    May 2014      314,500      796,750

(1) These amounts represent the result of calculations at the 5% and 10% assumed compounded appreciation rates from the date of grant to the end of the option term (i.e., the expiration date) as required by the Commission by Item 402(c)(2)(vi)(A) of Regulation S-K and are not intended to forecast the future trading prices of Enterprise Products Partners’ common units.

 

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Common Unit Options Exercised by Named Executive Officers and Fiscal Year-End Values . The following table provides certain information concerning (i) the exercise of options to purchase Enterprise Products Partners’ common units by each named executive officer during 2004 and (ii) the value of unexercised common unit options at December 31, 2004. Mr. Andras did not hold any options to purchase Enterprise Products Partners’ common units at December 31, 2004 nor did he exercise any options during 2004.

 

    

Units
Acquired
on

Exercise(#)


  

Value

Realized($)(1)


  

Number of

Securities Underlying
Unexercised Options

at December 31, 2004


  

Value of

Unexercised

In-the-Money Options

at December 31, 2004(2)


Name


         Exercisable

   Unexercisable

   Exercisable

   Unexercisable

A. J. Teague

   100,000    $ 1,057,000    100,000    35,000    $ 993,000    $ 205,100

Charles E. Crain

   60,000      768,000         25,000             146,500

James H. Collingsworth

               50,000    25,000      131,000      146,500

W. Ordemann

   40,000      258,000    50,000    25,000             146,500

(1) The “value realized” represents the difference between the exercise price of the common unit options and the market (sale) price of the common units on the date of exercise without considering any taxes that may have been owed by the beneficiary.
(2) The value is based on the $25.86 closing price of Enterprise Products Partners’ common units on December 31, 2004.

 

Compensation Committee Interlocks and Insider Participation

 

As stated above, the compensation of the executive officers of Enterprise Products GP is paid by EPCO, and Enterprise Products Partners reimburses EPCO for that portion of its compensation expense that is related to Enterprise Products Partners’ business, pursuant to the administrative services agreement. For the year ended December 31, 2004, O.S. Andras, the former Vice Chairman of EPCO, determined the amount of cash compensation paid by EPCO to the executive officers of Enterprise Products GP other than himself, and Dan L. Duncan, Chairman of EPCO determined the amount of cash compensation paid by EPCO to Mr. Andras. No compensation expense is borne by Enterprise Products Partners with respect to Mr. Duncan.

 

Equity Compensation Plan Information

 

The following table sets forth certain information as of December 31, 2004 regarding the equity compensation plan of EPCO under which Enterprise Products Partners’ common units are authorized for issuance to its key employees and to directors of Enterprise Products GP.

 

Plan Category


  

(A)

Number of
securities to
be issued
upon exercise
of outstanding
common unit
options


  

(B)

Weighted-

average
exercise price
of outstanding
common unit
options


  

(C)

Number of
securities
remaining
available for
future issuance
under equity
compensation
plans (excluding
securities
reflected in
column (A))


Equity compensation plans approved by unitholders:

                

1998 Plan

   2,463,000    $ 18.84    3,367,552

Equity compensation plans not approved by unitholders:

                

None

                

Total for equity compensation plans

   2,463,000    $ 18.84    3,367,552

 

The Enterprise Products 1998 Long-Term Incentive Plan, which we refer to as the 1998 Plan, is intended to promote Enterprise Products Partners’ interests by encouraging employees and directors of EPCO and its

 

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affiliates who perform services for Enterprise Products Partners to acquire or increase their ownership of common units of Enterprise Products Partners and to provide a means whereby they may develop a sense of proprietorship and personal involvement in Enterprise Products Partners’ development and financial success through the award of common unit options. The 1998 Plan was developed to encourage recipients of common unit options to remain with Enterprise Products Partners and to devote their best efforts to its business, thereby advancing the interests of all unitholders and Enterprise Products GP. The 1998 Plan also enhances Enterprise Products Partners’ ability to attract and retain the services of key individuals who are essential for its growth and profitability.

 

The 1998 Plan is governed by Enterprise Products GP’s audit and conflicts committee, whose significant powers include, but are not limited to, (i) designating participants in the plan; (ii) determining the number of common units to be covered by the equity awards; (iii) determining the terms and conditions of any equity award; and (iv) determining, whether, to what extent, and under what circumstances participants may settle, exercise, cancel or forfeit any equity award. Subject to adjustment as provided in the 1998 Plan documents, the aggregate number of common units that may be awarded to participants is 7,000,000, of which 3,367,552 remain available for awards at December 31, 2004. The common units to be awarded under this plan may be obtained through purchases made on the open market or from affiliates of EPCO or from Enterprise Products Partners.

 

The exercise price of common unit options issued to participants is determined by the committee (at its discretion) at the date of grant and may be equal to, greater or less than its fair market value as of the date of grant. The committee determines the time or times at which the awards may be exercised in whole or in part, and the method or methods by which any payment of the exercise price with respect thereto may be made or deemed to have been made, which may include cash, notes receivable from the participant, or cashless-broker transactions or other acceptable forms of payment. In addition, to the extent provided by the committee, a common unit option grant may include a contingent right to receive an amount in cash equal to any cash distributions made by Enterprise Products Partners with respect to the underlying common units during the period the award is outstanding.

 

The 1998 Plan also provides for the issuance of restricted common units. During 2004, a total of 434,225 restricted common units were issued to key employees of EPCO and our four independent directors under the 1998 Plan. A total of 1,000,000 restricted common units can be issued under the 1998 Plan, of which 565,775 remain authorized for issuance at December 31, 2004.

 

The 1998 Plan is effective until either all available common units under the plan have been issued to participants or the earlier termination of the 1998 Plan by EPCO. A second plan, the Enterprise Products 1999 Long-Term Incentive Plan, is inactive and has no options outstanding. At present, Enterprise Products Partners has no intention of issuing options under this second plan.

 

Commitments under Equity Compensation Plans of EPCO

 

Categories of Equity-Based Awards and Our General Commitments Under Each

 

Equity-based awards granted to certain key operations employees . Under the administrative services agreement, Enterprise Products Partners reimburses EPCO for the compensation of all operations personnel it employs on Enterprise Products Partners’ behalf. This includes the costs attributable to equity-based awards granted to these personnel. When these employees exercise unit options, Enterprise Products Partners reimburses EPCO for the difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units awarded to the employee. Enterprise Products Partners may reimburse EPCO for these costs by either furnishing cash, reissuing treasury units or by issuing new common units.

 

Equity-based awards granted to certain key administrative and management employees . Effective January 1, 2004, Enterprise Products Partners began reimbursing EPCO for the compensation of all administrative and

 

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management personnel it employs on Enterprise Products Partners’ behalf. This includes the costs attributable to equity-based awards granted to these personnel. When these employees exercise unit options, Enterprise Products Partners reimburses EPCO for the difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units awarded to the employee. Enterprise Products Partners may reimburse EPCO for these costs by either furnishing cash, reissuing treasury units or by issuing new common units.

 

Prior to January 1, 2004, Enterprise Products Partners’ compensation obligation was differentiated between administrative and management personnel EPCO hired in response to Enterprise Products Partners’ expansion and new business activities and those EPCO employees in administrative and management positions that were active at the time of Enterprise Products Partners’ initial public offering in July 1998. The cost of equity-based awards associated with such personnel hired in response to such expansion and new business activities was accounted for as described in the previous paragraph. The cost of equity-based awards associated with such personnel that were active at the time of Enterprise Products Partners initial public offering was covered under the administrative services fee Enterprise Products Partners paid to EPCO. EPCO was responsible for the actual costs when the unit awards granted to these pre-expansion employees are exercised. EPCO satisfied its equity-award obligations to the pre-expansion employees by arranging for common units to be purchased in the open market or from Enterprise Products Partners.

 

Commitments at December 31, 2004

 

At December 31, 2004, there were 2,463,000 options outstanding to purchase common units under the 1998 Plan that had been granted to employees for which Enterprise Products Partners was responsible for reimbursing EPCO for the costs of such awards. The weighted-average strike price of the unit option awards granted to this group was $18.84 per common unit at December 31, 2004 and 1,154,000 of these unit options were exercisable. An additional 374,000, 25,000 and 910,000 of these common unit options will be exercisable in 2005, 2006 and 2008, respectively.

 

Employee Unit Purchase Plan

 

The Enterprise Unit Purchase Plan gives all eligible employees the opportunity to purchase common units at a 10% discount from an average market price (as defined by the plan) through voluntary payroll deductions. The purchase price is paid 90% by the employee and 10% by EPCO (which amount is reimbursed by Enterprise Products Partners). Generally, an eligible employee is a regular, active full-time employee who has been employed by EPCO for at least three months and works on our business for at least 30 hours per week. During the year ended December 31, 2004, a total of 96,534 common units were purchased under this plan, at a cost of $0.2 million being incurred by EPCO for the 10% discount.

 

Compensation of Directors

 

Neither Enterprise Products Partners nor Enterprise Products GP provides any additional compensation to employees of EPCO who serve as directors of Enterprise Products GP. The employees of EPCO who served as directors of Enterprise Products GP during 2004 were Mr. Duncan, Mr. Andras and Mr. Phillips.

 

Enterprise Products GP’s independent outside directors—Messrs. Barnett, Snell and Ralls—are compensated for their services at the expense of Enterprise Products GP. Effective October 1, 2004, Enterprise Products GP revised the compensation arrangements for its independent directors as follows: (i) an annual retainer of $25,000 in cash and $25,000 worth of restricted common units and (ii) an annual retainer of $7,500 in cash for serving as chairman of a committee of the board of directors.

 

In addition, Mr. Snell has been granted options to acquire Enterprise Products Partners’ common units as a result of independent director compensation arrangements made prior to 2004. Mr. Snell had 40,000 common unit options at March 31, 2005.

 

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SECURITY OWNERSHIP OF CERTAIN

BENEFICIAL OWNERS AND MANAGEMENT

 

Enterprise GP Holdings

 

The following table sets forth certain information regarding the beneficial ownership of our units prior to and as of the closing of this offering by:

 

    each person who will beneficially own more than 5% of our units;

 

    each of the named executive officers of our general partner;

 

    all of the directors and director nominees of our general partner; and

 

    all of the directors, director nominees and executive officers of our general partner as a group.

 

All information with respect to beneficial ownership has been furnished by the respective directors or officers, as the case may be.

 

Name of Beneficial Owner:


   Units
Beneficially Owned
Prior to Offering


   

Units
Beneficially Owned
After Offering


 
     Units

   Percent

    Units

   Percent

 

Dan L. Duncan:

                      

Units owned by Dan Duncan LLC

   3,726,273    5.0 %   3,726,273    4.3 %

Units owned by EPCO (1)

   70,941,059    95.0 %   71,126,244    82.1 %

Units owned by employee partnership

   —      —       1,888,889    2.2 %

Units owned by Duncan Family 2000 Trust

   —      —       185,185    0.2 %
    
  

 
  

Total for Dan L. Duncan

   74,667,332    100 %   76,926,591    88.8 %

Michael A. Creel

   —      —               

Richard H. Bachmann

   —      —               

W. Randall Fowler

   —      —               

Michael J. Knesek

   —      —               

Charles E. McMahen

   —      —               

Edwin E. Smith

   —      —               

All directors, director nominees and executive officers of of EPE Holdings, LLC, as a group (7 individuals in total)

   74,667,332    100 %                %  

(1) EPCO owns its units through wholly owned subsidiaries. Mr. Duncan owns 50.4% of the voting stock of EPCO and, accordingly, exercises sole voting and dispositive power with respect to the units beneficially owned by EPCO. All of these units will be pledged under a new credit facility to be entered into concurrently with the closing of this offering by EPCO Holdings Inc., a wholly owned subsidiary of EPCO. This credit facility will contain customary and other events of default relating to certain defaults of the borrower, us, Enterprise Products Partners and other EPCO affiliates. Upon an event of default, a change in control of us or Enterprise Products Partners could result. The address of EPCO is 2707 North Loop West, Houston, Texas 77008, and the address of Mr. Duncan is 2727 North Loop West, Houston, Texas 77008.

 

Enterprise Products Partners

 

The following table sets forth certain information as of July 15, 2005 regarding the beneficial ownership of Enterprise Products Partners’ units by:

 

    each person known by Enterprise Products GP to beneficially own more than 5% of Enterprise Products Partners’ common units;

 

    each of the named executive officers of Enterprise Products GP and our general partner;

 

    all of the directors of Enterprise Products GP; and

 

    all of the directors and executive officers of Enterprise Products GP as a group.

 

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All information with respect to beneficial ownership has been furnished by the respective directors or officers, as the case may be. Each person has sole voting and dispositive power over the units shown unless otherwise indicated below. Enterprise Products Partners had 384,695,836 common units outstanding at July 15, 2005.

 

     Common Units

 

Name of Beneficial Owner:


  

Number

of Units


   Percent of
Class


 

Dan L. Duncan:

           

Units owned by EPCO (1)

   131,532,923    34.3 %

Units owned by trusts (2)

   11,484,578    2.9 %

Units owned directly

   539,012    0.1 %
    
  

Total for Dan L. Duncan

   143,556,513    37.3 %

Shell US Gas & Power LLC (3)

   32,778,985    8.5 %

O.S. Andras (4)

   3,576,525    0.9 %

Robert G. Phillips

   85,337    *  

Richard S. Snell (5)

   50,906    *  

W. Matt Ralls

   4,624    *  

E. William Barnett

   269    *  

A.J. Teague (4)(6)

   241,977    *  

Charles E. Crain (4)

   157,774    *  

James H. Collingsworth (4)(7)

   66,877    *  

W. Ordemann (4)

   71,898    *  

Michael A. Creel (8)

   192,848    *  

Richard H. Bachmann (9)

   169,511    *  

W. Randall Fowler

   42,057    *  

Michael J. Knesek (10)

   36,150    *  

All directors and executive officers of Enterprise Products GP as a group (21 individuals in total) (11)

   181,032,251    47.1 %

  * The beneficial ownership of each is less than 1% of Enterprise Products Partners’ common units outstanding.
(1) The 131,532,923 common units owned by EPCO include 118,078,425 common units owned through a wholly owned subsidiary, DFI Delaware Holdings, L.P., and the 13,454,498 common units to be contributed to us at the closing of this offering. Mr. Duncan owns 50.4% of the voting stock of EPCO and, accordingly, exercises sole voting and dispositive power with respect to the units beneficially owned by EPCO. The remaining shares of EPCO capital stock are owned primarily by trusts for the benefit of the members of Mr. Duncan’s family. EPCO has pledged substantially all of its common units and its ownership in Enterprise Products GP as security under its 364-day bridge loan. EPCO’s bridge loan contains customary and other events of default relating to defaults of EPCO and certain of its subsidiaries, including certain defaults of Enterprise Products Partners and other EPCO affiliates. Upon an event of default, a change in control of Enterprise Products Partners or Enterprise Products GP could result. The 13,454,498 common units to be contributed to us will be released from the pledge concurrently with the closing of this offering and repledged as security under our new credit facility. The address of EPCO is 2707 North Loop West, Houston, Texas 77008 and the address of Mr. Duncan is 2727 North Loop West, Houston, Texas, 77008.
(2) In addition to the units owned by EPCO, Dan L. Duncan is deemed to be the beneficial owner of the common units owned by the Duncan Family 1998 Trust and Duncan Family 2000 Trust, the beneficiaries of which are the shareholders of EPCO.
(3) Enterprise Products Partners issued these units to Shell US Gas & Power LLC (an affiliate of Shell) in connection with its acquisition of certain of Shell’s U.S. Gulf Coast midstream energy assets in 1999 and a related contingent unit agreement. The address of Shell US Gas & Power LLC is 910 Louisiana Street, Houston, Texas 77002.

 

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(4) These individuals are the “named executive officers” for 2004.
(5) Mr. Snell’s beneficial ownership amount includes 40,000 common unit options issued under the equity compensation plan of EPCO that are exercisable within 60 days. The number of common units shown for Mr. Snell include 6,000 common units held by family trusts and 1,100 common units owned by his wife, for which he has disclaimed beneficial ownership.
(6) Mr. Teague’s beneficial ownership amount includes 100,000 common unit options issued under the equity compensation plan of EPCO that are exercisable within 60 days.
(7) Mr. Collingsworth’s beneficial ownership amount includes 50,000 common unit options issued under the equity compensation plan of EPCO that are exercisable within 60 days.
(8) Mr. Creel’s beneficial ownership amount includes 100,000 common unit options issued under the equity compensation plan of EPCO that are exercisable within 60 days.
(9) Mr. Bachmann’s beneficial ownership amount includes 80,000 common unit options issued under the equity compensation plan of EPCO that are exercisable within 60 days.
(10) Mr. Knesek’s beneficial ownership amount includes 20,000 common unit options issued under the equity compensation plan of EPCO that are exercisable within 60 days.
(11) Cumulatively, this group’s beneficial ownership amount includes 640,000 common unit options issued under the equity compensation plan of EPCO that are exercisable within 60 days.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

 

Our Relationship with EPCO, Enterprise Products GP and Enterprise Products Partners

 

We are the sole member of Enterprise Products GP. Enterprise Products GP is the general partner of Enterprise Products Partners. Our assets currently consist of the following partnership interests in Enterprise Products Partners contributed to us by EPCO:

 

    a 100% ownership of Enterprise Products GP, which owns a 2% general partner interest in Enterprise Products Partners that entitles us to receive 2% of the cash distributed by Enterprise Products Partners;

 

    the incentive distribution rights associated with Enterprise Products Partners’ general partner interest, which entitle us to receive increasing percentages of the cash distributed by Enterprise Products Partners (up to a maximum of 25%) as Enterprise Products Partners’ per unit distribution increases; and

 

    13,454,498 common units of Enterprise Products Partners, representing an approximate 3.4% limited partner interest in Enterprise Products Partners.

 

In connection with the contribution of certain of these partnership interests to us, we assumed $159.6 million of indebtedness owed to EPCO. This indebtedness with respect to these assets was originally incurred in January 2005 by EPCO to purchase as a portion of the purchase price 13,454,498 common units in Enterprise Products Partners and a 9.9% membership interest in Enterprise Products GP from El Paso Corporation. This indebtedness matures in May 2020 and bears interest at approximately 6.25% per annum. This indebtedness will be repaid with our new credit facility concurrently with the closing of this offering.

 

Enterprise Products Partners is required by its partnership agreement to distribute all cash on hand at the end of each quarter, less appropriate reserves determined by the board of directors of its general partner. Since its initial public offering in 1998, Enterprise Products Partners has increased its quarterly distribution by approximately 87%, from $0.225 per unit, or $0.90 per unit on an annualized basis, to $0.42 per unit, or $1.68 per unit on an annualized basis. Based on Enterprise Products Partners’ quarterly distribution of $0.42 per unit declared and payable with respect to the second quarter of 2005 and the number of its common units outstanding at July 15, 2005, we would be entitled to receive a quarterly cash distribution of approximately $25.7 million (or approximately $102.8 million on an annualized basis), which consists of $3.3 million from Enterprise Products GP’s 2% general partner interest, $16.7 million from the associated incentive distribution rights and $5.7 million from the common units of Enterprise Products Partners that we own.

 

We expect to have an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is also a director and Chairman of each of our general partner and Enterprise Products GP. Our general partner manages our operations and activities. These functions will be performed by the employees of EPCO pursuant to an amended and restated administrative services agreement under the direction of the board of directors and executive officers of our general partner. Our general partner and its affiliates will not receive any management fee or other compensation for the management of our operations and activities but will be reimbursed for direct and indirect expenses incurred on our behalf. Please read “—Administrative Services Agreement.” All of the executive officers and non-independent directors of our general partner also serve as executive officers or directors of Enterprise Products GP.

 

Related Party Transactions of Enterprise Products GP

 

On September 30, 2004, Enterprise Products GP borrowed $370 million from Dan Duncan LLC, which prior to this offering owned a 4.505% membership interest in Enterprise Products GP. Enterprise Products GP used the proceeds from this borrowing to fund the cash portion of the consideration paid to El Paso for a 50% membership interest in GulfTerra’s general partner. This promissory note bears a fixed-interest rate of 6.25%. Installment payments of $6.6 million are due quarterly from November 2004 through November 2019. Under terms of the note agreement, Enterprise Products GP is allowed to defer up to $13.2 million of scheduled

 

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quarterly installment payments at any time, except that all principal and accrued interest must be repaid by the November 2019 maturity date. As of March 31, 2005, there was $365.4 million principal amount outstanding under this note. This note will be repaid with our new credit facility concurrently with the closing of this offering.

 

Related Party Transactions of Enterprise Products Partners

 

The following table summarizes Enterprise Products Partners’ related party transactions for the periods indicated (in thousands of dollars):

 

     For Year Ended December 31,

   For the Three Months
Ended March 31,


     2004

   2003

   2002

   2005

   2004

Revenues from consolidated operations

                                  

EPCO and subsidiaries

   $ 2,697    $ 4,241    $ 3,630    $ 284    $ 2,143

Shell

     542,912      293,109      282,820             104,100

Unconsolidated affiliates

     258,541      266,894      196,267      57,909      49,060
    

  

  

  

  

Total

   $ 804,150    $ 564,244    $ 482,717    $ 58,193    $ 155,303
    

  

  

  

  

Operating costs and expenses

                                  

EPCO and subsidiaries

   $ 202,561    $ 149,626    $ 103,210    $ 57,044    $ 39,113

TEPPCO

                          1,503       

Shell

     725,420      607,277      531,712             166,830

Unconsolidated affiliates

     37,587      43,752      60,657      6,568      9,582
    

  

  

  

  

Total

   $ 965,568    $ 800,655    $ 695,579    $ 65,115    $ 215,525
    

  

  

  

  

General and administrative expenses

                                  

EPCO

   $ 28,107    $ 27,960    $ 24,204    $ 9,251    $ 6,894
    

  

  

  

  

 

Relationship with EPCO. Enterprise Products Partners has an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is also a director and chairman of Enterprise Products GP. In addition, the executive and other officers of Enterprise Products GP are employees of EPCO, including Robert G. Phillips who is chief executive officer and a director of Enterprise Products GP. The principal business activity of Enterprise Products GP is to act as Enterprise Products Partners’ managing partner.

 

Mr. Duncan owns 50.4% of the voting stock of EPCO. The remaining shares of EPCO capital stock are held primarily by trusts for the benefit of members of Mr. Duncan’s family. In addition, at December 31, 2004, EPCO and Dan Duncan LLC, together, owned 90.1% of the membership interests of Enterprise Products GP, which in turn owned a 2% general partner interest in Enterprise Products Partners. In January 2005, an affiliate of EPCO acquired El Paso’s 9.9% membership interest in Enterprise Products GP. As a result of this transaction, EPCO and its affiliates own 100% of Enterprise Products GP.

 

In addition, trust affiliates of EPCO, the beneficiaries of which are the shareholders of EPCO (the 1998 Trust and 2000 Trust), owned 11,484,578 of Enterprise Products Partners’ common units at July 15, 2005. Collectively, Mr. Duncan, through his beneficial ownership of Enterprise Products Partners’ common units held personally, by the 1998 and 2000 Trusts and through subsidiaries of EPCO, controlled 37.3% of Enterprise Products Partners’ common units at July 15, 2005.

 

Enterprise Products Partners’ agreements with EPCO are not the result of arm’s-length transactions, and there can be no assurance that any of the transactions provided for therein are effected on terms at least as favorable to the parties to such agreement as could have been obtained from unaffiliated third parties.

 

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Other related party transactions with EPCO . The following is a summary of other significant related party transactions between EPCO and Enterprise Products Partners, including those between EPCO and Enterprise Products Partners’ unconsolidated affiliates.

 

    Prior to January 1, 2004, EPCO was the operator of Enterprise Products Partners’ MTBE facility and Houston Ship Channel NGL import facility. During 2003 and 2002, Enterprise Products Partners paid EPCO $0.8 million for such services. Such payments were terminated effective January 1, 2004.

 

    Enterprise Products Partners has an agreement with EPCO to provide trucking services for the transportation of NGLs and other products. Enterprise Products Partners paid EPCO $14.2 million, $12.3 million and $8.6 million for such trucking services during the years ended December 31, 2004, 2003 and 2002, respectively. Enterprise Products Partners paid EPCO $3.6 million and $3.4 million for such services during the three months ended March 31, 2005 and 2004, respectively.

 

    In the normal course of business, Enterprise Products Partners also buys from and sells certain NGL products to EPCO. Enterprise Products Partners purchased $71.8 million, $47.2 million and $40.9 million of such products from EPCO during the years ended December 31, 2004, 2003 and 2002, respectively. Enterprise Products Partners purchased $12.5 million and $11.9 million of such products from EPCO during the three months ended March 31, 2005 and 2004, respectively. Enterprise Products Partners sold $2.7 million, $4.5 million and $3.6 million of such products to EPCO during the years ended December 31, 2004, 2003 and 2002, respectively. In addition, Enterprise Products Partners sold $0.3 million and $2.1 million of such products to EPCO during the three months ended March 31, 2005 and 2004, respectively.

 

Enterprise Products Partners and Enterprise Products GP are separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from EPCO and its other affiliates. EPCO primarily depends on the cash distributions it receives as an equity owner in Enterprise Products Partners and its other investments (including the recent acquisition of TEPPCO Partners’ general partner and 2,500,000 common units of TEPPCO Partners) to fund its other operations and to meet its debt obligations. Substantially all of the common units of Enterprise Products Partners (other than the 13,454,498 common units we own) and all of the units of Enterprise GP Holdings owned or controlled by EPCO and its affiliates (other than Dan Duncan LLC and the trusts affiliated with Dan L. Duncan) will be pledged as security under a credit facility to be entered into concurrently with the closing of this offering by EPCO Holdings Inc., a wholly owned subsidiary of EPCO. In the event of a default under such credit facility, a change in control of us and Enterprise Products Partners could occur.

 

For the three months ended March 31, 2005 and 2004, EPCO received $46.8 million and $43.4 million, respectively, in cash distributions from Enterprise Products Partners. For the years ended December 31, 2004, 2003 and 2002, EPCO received $173.7 million, $160.4 million and $146.6 million, respectively, in quarterly cash distributions from Enterprise Products Partners.

 

Relationship with TEPPCO . On February 24, 2005, an affiliate of EPCO acquired TEPPCO GP, the general partner of TEPPCO, and 2,500,000 common units of TEPPCO from Duke Energy for approximately $1.2 billion in cash. TEPPCO GP owns a 2% general partner interest in TEPPCO and is the managing partner of TEPPCO and its subsidiaries. Subsequently, EPCO reconstituted the board of directors of TEPPCO GP, and Dr. Ralph Cunningham (a former independent director of Enterprise Products GP) was named Chairman of TEPPCO GP, and Lee W. Marshall, Sr. (a former independent director of Enterprise Products GP) was also elected a director of TEPPCO GP. Due to EPCO’s actions to reconstitute the board of directors of TEPPCO GP and TEPPCO GP’s ability to direct the management of TEPPCO, TEPPCO GP and TEPPCO became related parties to EPCO and Enterprise Products Partners during the first quarter of 2005.

 

On March 11, 2005, the Bureau of Competition of the FTC delivered written notice to EPCO’s legal advisor that it was conducting a non-public investigation to determine whether EPCO’s acquisition of TEPPCO GP may tend substantially to lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with EPCO’s purchase of TEPPCO GP. EPCO and its affiliates, including Enterprise Products Partners, may

 

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receive similar inquiries from other regulatory authorities and intend to cooperate fully with any such investigations and inquiries. In response to such FTC investigation or any inquiries EPCO and its affiliates may receive from other regulatory authorities, Enterprise Products Partners may be required to divest certain assets. In the event Enterprise Products Partners is required to divest significant assets, its financial condition could be affected.

 

Relationship with Shell. Enterprise Products Partners has a significant commercial relationship with Shell as a partner, customer and vendor. At July 15, 2005, Shell owned approximately 8.5% of Enterprise Products Partners’ common units. Historically, Shell was considered a related party because it owned more than 10% of Enterprise Products Partners’ limited partner interests and, prior to September 2003, it owned a 30% ownership interest in Enterprise Products GP. As a result of Shell selling a portion of its limited partner interests in Enterprise Products Partners to a third party in December 2004 and March 2005, Shell now owns less than 10% of its common units. Shell sold its 30% interest in Enterprise Products GP to an affiliate of EPCO in September 2003. As a result of Shell’s reduced equity interest and lack of control of Enterprise Products Partners, Shell ceased to be considered a related party beginning in the first quarter of 2005.

 

Shell is one of Enterprise Products Partners’ largest customers. For the years ended December 31, 2004, 2003 and 2002, Shell accounted for 6.5%, 5.5% and 7.9%, respectively, of Enterprise Products Partners’ consolidated revenues. Enterprise Products Partners’ revenues from Shell primarily reflect the sale of NGL and petrochemical products to Shell and the fees Enterprise Products Partners charge Shell for natural gas processing, pipeline transportation and NGL fractionation services. Enterprise Products Partners’ operating costs and expenses with Shell primarily reflect the payment of energy-related expenses related to the Shell natural gas processing agreement and the purchase of NGL products from Shell. Enterprise Products Partners also lease from Shell its 45.4% interest in one of Enterprise Products Partners’ propylene fractionation facilities located in Mont Belvieu, Texas.

 

The most significant contract affecting Enterprise Products Partners’ natural gas processing business is the Shell margin-band/keepwhole processing agreement, which grants Enterprise Products Partners the right to process Shell’s current and future production within state and federal waters of the Gulf of Mexico. The Shell processing agreement includes a life of lease dedication, which may extend the agreement well beyond its initial 20-year term ending in 2019. For additional information regarding this contract, please read “Business of Enterprise Products Partners—NGL Pipelines & Services—Natural Gas Processing and Related NGL Marketing Activities.”

 

Enterprise Products Partners has also completed a number of business acquisitions and asset purchases involving Shell since 1999, including the acquisition of midstream energy assets located along the Gulf Coast for approximately $528.8 million in 1999; the purchase of the Lou-Tex Propylene pipeline for $100 million in 2000; and the acquisition of the Acadian Gas pipeline system in 2001 for $243.7 million.

 

On March 3, 2005, Enterprise Products Partners filed a universal shelf registration statement with the Commission registering the issuance of $4 billion of partnership equity and public debt obligations. In connection with this registration statement, Enterprise Products Partners also registered for resale 36,572,122 common units currently owned by Shell and 4,427,878 common units that had been sold by Shell to Kayne Anderson MLP Investment Company. Shell sold these unregistered units to Kayne Anderson in December 2004. Enterprise Products Partners is obligated to register the resale of these common units under a registration rights agreement it executed with Shell in connection with its acquisition of certain of Shell’s Gulf Coast midstream energy businesses in September 1999.

 

Relationships with unconsolidated affiliates. Enterprise Products Partner’s investment in unconsolidated affiliates with industry partners is a vital component of its business strategy. These investments are a means by which Enterprise Products Partners conducts its operations to align its interests with a supplier of raw materials or a consumer of finished products. This method of operation also enables Enterprise Products Partners to

 

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achieve favorable economies of scale relative to the level of investment and business risk assumed versus what Enterprise Products Partners could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to Enterprise Products Partners’ other business operations. The following summarizes significant related party transactions Enterprise Products Partners has with its current unconsolidated affiliates:

 

    Enterprise Products Partners sells natural gas to Evangeline, which, in turn, uses the natural gas to satisfy supply commitments it has with a major Louisiana utility. For the three months ended March 31, 2005 and 2004, revenues from Evangeline were $53.3 million and $43.8 million, respectively. For the years ended December 31, 2004, 2003 and 2002, revenues from Evangeline were $233.9 million, $212.7 million and $131.6 million, respectively. In addition, Enterprise Products Partners has also furnished $11.1 million in letters of credit on behalf of Evangeline.

 

    Enterprise Products Partners paid transportation fees to Dixie (prior to its consolidation with our results beginning in February 2005) for propane movements on their system initiated by its NGL marketing activities. For the three months ended March 31, 2005 and 2004, Enterprise Products Partners paid Dixie $1.2 million and $4.2 million, respectively, in such transportation fees. For the years ended December 31, 2004, 2003 and 2002, Enterprise Products Partners paid Dixie $13.1 million, $11.3 million and $12.2 million, respectively, in such transportation fees.

 

    Enterprise Products Partners pays Promix for the transportation, storage and fractionation of certain of its mixed NGL volumes. In addition, Enterprise Products Partners sells natural gas to Promix for their fuel requirements. For the three months ended March 31, 2005 and 2004, Enterprise Products Partners paid Promix $5.3 million and $5 million, respectively, for their services. For the years ended December 31, 2004, 2003 and 2002, Enterprise Products Partners paid Promix $23.2 million, $17.5 million and $18.4 million, respectively, for their services. Additionally, for the three months ended March 31, 2005 and 2004, revenues from Promix for the purchase of natural gas were $3.1 million and $4 million, respectively. For the years ended December 31, 2004, 2003 and 2002, revenues from Promix for the purchase of natural gas were $18.6 million, $19.6 million and $12.7 million, respectively.

 

Prior to its becoming a consolidated subsidiary in March 2003, Enterprise Products Partners paid EPIK for export services to load product cargoes for its NGL and petrochemical marketing customers. Also, prior to its becoming a consolidated subsidiary in September 2003, Enterprise Products Partners sold high purity isobutane to BEF as a feedstock and purchased certain of BEF’s by-products. Enterprise Products Partners also received transportation fees for BEF’s shipments of MTBE on its HSC pipeline and fractionation revenues for reprocessing mixed feedstock streams generated by BEF.

 

Enterprise Products Partners enters into management agreements with some of its unconsolidated affiliates under which its unconsolidated affiliates pay it management fees for the operation and management of their assets. For the three months ended March 31, 2005 and 2004, such fees approximated $1.8 million and $0.4 million, respectively. For the years ended December 31, 2004, 2003 and 2002, such fees approximated $2.1 million, $1.5 million and $1.4 million, respectively. Additionally, on occasion Enterprise Products Partners pays for construction costs on behalf of its unconsolidated affiliates during the initial construction phase of their assets, and these amounts are settled by direct reimbursements for the amounts Enterprise Products Partners are owed from its unconsolidated affiliates.

 

Administrative Services Agreement

 

Administrative Services Agreement . Enterprise Products Partners has no employees. All of its management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement. Under the administrative services agreement, EPCO has agreed to:

 

    employ the personnel necessary to manage Enterprise Products Partners’ business and affairs (through Enterprise Products GP);

 

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    employ the operating personnel involved in Enterprise Products Partners’ business;

 

    allow Enterprise Products Partners to participate as a named insured in EPCO’s current insurance program with the costs being allocated among the parties on the basis set forth in the agreement; and

 

    sublease to Enterprise Products Partners certain equipment which it holds pursuant to operating leases for one dollar per year and to assign to us its purchase option under such leases. EPCO remains liable for the cash lease payments associated with these assets.

 

Costs and expenses include $136.2 million, $108.7 million and $68.8 million of reimbursements paid to EPCO, primarily for compensation costs directly related to the operating and management personnel EPCO employed on behalf of Enterprise Products Partners during the years ended December 31, 2004, 2003 and 2002, respectively. Enterprise Products Partners reimbursed EPCO $50.1 million and $28.2 million for such costs during the three months ended March 31, 2005 and 2004, respectively.

 

Operating costs and expenses (as shown in Enterprise Products GP’s Statements of Consolidated Operations and Comprehensive Income) treat the retained lease-related payments made by EPCO on Enterprise Products Partners’ behalf as a non-cash related party operating expense, with the offset to partners’ equity on the Consolidated Balance Sheets recorded as a general contribution to the partnership. The non-cash retained lease expense amounts recorded by Enterprise Products Partners for the years ended December 31, 2004, 2003 and 2002 were $7.7 million, $9.1 million and $9.1 million, respectively. Such amounts were $0.5 million and $2.3 million for the three months ended March 31, 2005 and 2004, respectively. As of March 31, 2005 and December 31, 2004, the remaining retained leases were for a cogeneration unit and approximately 100 railcars. During 2004, Enterprise Products Partners exercised its options to purchase an isomerization unit and related equipment at a cost of $17.8 million. Should Enterprise Products Partners decide to exercise the purchase options associated with the remaining retained leases (which are also at fair value), an additional $2.3 million would be payable in 2008 and $3.1 million in 2016. In addition to retained lease expense, operating costs and expenses include compensation charges for EPCO’s employees who operate Enterprise Products Partners’ facilities.

 

General and administrative costs (as shown in Enterprise Products GP’s Statements of Consolidated Operations and Comprehensive Income) include the costs Enterprise Products Partners pays EPCO for administrative support. Prior to January 1, 2004, Enterprise Products Partners’ payments to EPCO and related non-cash expenses for administrative support were based on the following:

 

    Enterprise Products Partners reimbursed EPCO for its share of the costs of certain EPCO employees in administrative positions that were active at the time of Enterprise Products Partners’ initial public offering in July 1998, who we refer to as the pre-expansion administrative personnel. This includes costs associated with equity-based awards granted to certain individuals within this group. Enterprise Products Partners’ obligation for reimbursing these costs was covered by an administrative service fee. Enterprise Products Partners paid $17.9 million and $16.6 million of such fees to EPCO during 2003 and 2002, respectively.

 

    To the extent that EPCO’s actual cost of providing the pre-expansion administrative personnel exceeded the administrative service fee charged Enterprise Products Partners during a given year, Enterprise Products Partners recorded a non-cash expense equal to the difference as a non-cash selling, general and administrative cost. The offset was recorded in partners’ equity on the Consolidated Balance Sheets as a general contribution to the partnership. The actual amounts incurred by EPCO for providing these services did not materially exceed the capped amount for the year ended December 31, 2002. For the year ended December 31, 2003, Enterprise Products Partners recorded $0.4 million in non-cash expense related to this excess.

 

    Enterprise Products Partners also reimburses EPCO for all costs it incurs related to administrative personnel it hires in response to Enterprise Products Partners’ expansion and new business activities. This includes costs attributable to equity-based awards granted to members of this group.

 

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Effective January 1, 2004, the administrative services agreement was amended to eliminate the fixed administrative service fee and to provide that Enterprise Products Partners reimburse EPCO for all costs related to administrative support regardless of whether the costs are related to pre-expansion or expansion personnel who work on our behalf.

 

On October 22, 2004, the administrative services agreement was amended further to evidence Enterprise Products Partners’ separateness from other persons and entities, to reflect a five-year license Enterprise Products Partners granted for EPCO’s use of service marks owned by Enterprise Products Partners and to provide for reimbursement of EPCO’s costs of discontinuing the use of those service marks over the term of the license. This amendment also provides that if EPCO and its affiliates (other than TEPPCO and its subsidiaries, which were excluded by a subsequent amendment) are offered by a third party, or discover an opportunity to acquire from a third party, a business or assets that is or are in the same or similar line of business then being conducted by the Operating Partnership or in a line of business that would be a natural extension of any business then being conducted by the Operating Partnership (a “Business Opportunity”), EPCO shall promptly advise the board of directors of Enterprise Products GP of such Business Opportunity and offer such Business Opportunity to the Operating Partnership. If the board of directors of Enterprise Products GP does not advise EPCO within 10 days following the receipt of such notice that Enterprise Products Partners wishes to pursue such Business Opportunity, EPCO shall then be permitted to pursue such Business Opportunity. If the board of directors of Enterprise Products GP advises EPCO within such 10-day period that Enterprise Products Partners wishes to pursue such Business Opportunity, EPCO shall not be permitted to pursue such Business Opportunity unless the board of directors of Enterprise Products GP subsequently advises EPCO that it has abandoned its pursuit of such Business Opportunity.

 

In connection with the closing of this offering, the administrative services agreement will be amended and restated. The amended and restated administrative services agreement will, among other things:

 

    Establish the business opportunity agreements described under the heading “Conflicts of Interest and Business Opportunity Agreements; Fiduciary Duties—Conflicts of Interest and Business Opportunity Agreements—Administrative Services Agreement.”

 

    Provide that EPCO will provide to us selling, general and administrative services and such management and operating services as may be necessary to manage and operate our business, properties and assets (in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to cause our business, properties and assets to be so managed and operated.

 

    Require that we pay to EPCO an amount equal to the sum of all costs and expenses (direct or indirect) incurred by EPCO which are directly or indirectly related to our business or activities (including expenses, direct or indirect, reasonably allocated to us by EPCO). In addition, we will agree to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided to us by EPCO.

 

    Allow us to participate as a named insured in EPCO’s current insurance program with the costs being allocated among the parties on the basis set forth in the agreement.

 

Indemnification of Directors and Officers

 

Under our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events any director or officer, or while serving as a director of officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person who is or was an employee (other than an officer) or agent of our partnership.

 

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CONFLICTS OF INTEREST AND BUSINESS OPPORTUNITY AGREEMENTS; FIDUCIARY DUTIES

 

Conflicts of Interest and Business Opportunity Agreements

 

Acquisitions of Competing Businesses. From time to time, we or our affiliates may acquire entities whose businesses compete with us or Enterprise Products Partners. For example, in February 2005, an affiliate of EPCO acquired all of the membership interests of Texas Eastern Products Pipeline Company, LLC, which owns a 2% general partner interest in and is the general partner of TEPPCO Partners, L.P. In a related transaction, an affiliate of EPCO acquired 2.5 million common units of TEPPCO Partners. TEPPCO Partners owns and operates one of the largest systems of common carrier pipelines transporting refined petroleum products and liquified petroleum gases in the United States; owns and operates petrochemical and NGL pipelines; is engaged in crude oil transportation, storage, gathering and marketing; owns and operates natural gas gathering systems; and owns 50-percent interests in Seaway Crude Pipeline Company, Centennial Pipeline LLC, and Mont Belvieu Storage Partners, L.P., and an undivided ownership interest in the Basin Pipeline. Purchasers of units in this offering will not benefit from the cash generated by TEPPCO Partners and its subsidiaries. Please read “Risk Factors—Enterprise Products Partners could be required to divest significant assets as a result of a non-public investigation by the Bureau of Competition of the Federal Trade Commission.”

 

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

 

Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our partners. All of our general partner’s executive officers and non-independent directors also serve as executive officers or directors of Enterprise Products GP and, as a result, have fiduciary duties to manage the business of Enterprise Products Partners in a manner beneficial to Enterprise Products Partners and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to Enterprise Products Partners, on the one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders. For a more detailed description of the conflicts of interest involving our general partner, please read “Conflicts of Interest and Business Opportunity Agreements; Fiduciary Duties.”

 

Potential Future Conflicts . Future conflicts of interest may arise among us and any entities whose general partner interests we or our affiliates acquire or among Enterprise Products Partners, TEPPCO Partners and such entities. It is not possible to predict the nature or extent of these potential future conflicts of interest at this time, nor is it possible to determine how we will address and resolve any such future conflicts of interest. However, the resolution of these conflicts may not always be in our best interest or that of our unitholders. We do not currently intend to take any action which would limit the ability of Enterprise Products Partners to pursue its business strategy.

 

Administrative Services Agreement. EPCO, Enterprise Products Partners, Enterprise Products GP and certain affiliated entities are parties to an administrative services agreement, effective as of October 1, 2004. As amended to date, this administrative services agreement provides, among other things, that if the EPCO Group, which includes EPCO and its affiliates (excluding Enterprise Products Partners, Enterprise Products GP and Enterprise Products Operating L.P. and certain affiliated parties, which excluded parties we refer to as partnership entities, and also excluding TEPPCO Partners, its general partner and their controlled affiliates), is offered by a third party, or discovers an opportunity to acquire from a third party, a business or assets that is or are in the same or similar line of business then being conducted by a partnership entity or in a line of business

 

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that would be a natural extension of any business then being conducted by a partnership entity, which we refer to as a business opportunity, the EPCO Group must promptly advise the board of directors of Enterprise Products GP of such business opportunity and offer such business opportunity to Enterprise Products Partners. If the board of directors of Enterprise Products GP does not advise the EPCO Group within ten days following the receipt of such notice that Enterprise Products Partners wishes to pursue such business opportunity, the EPCO Group will be permitted to pursue such business opportunity. If the board of directors of Enterprise Products GP advises the EPCO Group within such ten-day period that Enterprise Products Partners wishes to pursue such business opportunity, the EPCO Group will not be permitted to pursue such business opportunity unless the board of directors of Enterprise Products GP subsequently advises the EPCO Group that Enterprise Products Partners has abandoned its pursuit of such business opportunity.

 

In connection with the closing of this offering, this administrative services agreement will be amended and restated to address potential conflicts that may arise among us, Enterprise Products Partners, Enterprise Products GP and the EPCO Group. The amended and restated administrative services agreement will provide, among other things, that:

 

    if a business opportunity to acquire equity securities is presented to the EPCO Group, us, our general partner, Enterprise Products GP or Enterprise Products Partners, then we will have the first right to pursue such opportunity. “Equity securities” are defined to include:

 

    general partner interests (or securities which have characteristics similar to general partner interests) and incentive distribution rights or similar rights in publicly traded partnerships or interests in “persons” that own or control such general partner or similar interests (collectively, GP Interests ) and securities convertible, exercisable, exchangeable or otherwise representing ownership or control of such GP Interests; and

 

    incentive distribution rights and limited partner interests (or securities which have characteristics similar to incentive distribution rights or limited partner interests) in publicly traded partnerships or interests in “persons” that own or control such limited partner or similar interests (collectively, “non-GP Interests”); provided that such non-GP Interests are associated with GP Interests and are owned by the owners of GP Interests or their respective affiliates.

 

We will be presumed to desire to acquire the equity securities until such time as our general partner advises the EPCO Group and Enterprise Products GP that we have abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to exceed $100 million, the decision to decline the acquisition will be made by the chief executive officer of our general partner after consultation with and subject to the approval of the audit and conflicts committee of our general partner. If the purchase price is reasonably likely to be less than such threshold amount, the chief executive officer of our general partner may make the determination to decline the acquisition without consulting the audit and conflicts committee of our general partner. In the event that we abandon the acquisition and so notify the EPCO Group and Enterprise Products GP, Enterprise Products Partners will have the second right to the pursue such acquisition. Enterprise Products Partners will be presumed to desire to acquire the equity securities until such time as Enterprise Products GP advises the EPCO Group that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to us, as described above but utilizing Enterprise Products GP’s chief executive officer and audit and conflicts committee. In the event that Enterprise Products Partners abandons the acquisition and so notifies the EPCO Group, the EPCO Group may pursue the acquisition without any further obligation to any other party or offer such opportunity to other affiliates.

 

   

if any business opportunity not covered by the preceding bullet point is presented to the EPCO Group, us, our general partner, Enterprise Products GP or Enterprise Products Partners, Enterprise Products Partners will have the first right to pursue such opportunity. Enterprise Products Partners will be presumed to desire to pursue the business opportunity until such time as Enterprise Products GP advises

 

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the EPCO Group and our general partner that Enterprise Products Partners has abandoned the pursuit of such business opportunity. In the event that the purchase price or cost associated with the business opportunity is reasonably likely to exceed $100 million, the decision to decline the business opportunity will be made by the chief executive officer of Enterprise Products GP after consultation with and subject to the approval of the audit and conflicts committee of Enterprise Products GP. If the purchase price or cost is reasonably likely to be less than such threshold amount, the chief executive officer of Enterprise Products GP may make the determination to decline the business opportunity without consulting Enterprise Products GP’s audit and conflicts committee. In the event that Enterprise Products Partners abandons the business opportunity and so notifies the EPCO Group and our general partner, we will have the second right to the pursue such business opportunity. We will be presumed to desire to pursue such business opportunity until such time as our general partner advises the EPCO Group that we have abandoned the pursuit of such business opportunity. In determining whether or not to pursue the business opportunity, we will follow the same procedures applicable to Enterprise Products Partners, as described above but utilizing our general partner’s chief executive officer and audit and conflicts committee. In the event that we abandon the business opportunity and so notify the EPCO Group, the EPCO Group may pursue the business opportunity without any further obligation to any other party or offer such opportunity to other affiliates.

 

For additional information concerning the amended administrative services agreement, please read “Certain Relationships and Related Party Transactions—Administrative Services Agreement.”

 

Conflicts Between Our General Partner and its Affiliates and Our Partners . Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

 

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:

 

    approved by the audit and conflicts committee, although our general partner is not obligated to seek such approval;

 

    approved by the vote of a majority of the outstanding units, excluding any units owned by our general partner or any of its affiliates;

 

    on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

    fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

 

Our general partner may, but is not required to, seek the approval of such resolution from the audit and conflicts committee of its board of directors. If our general partner does not seek approval from the audit and conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the audit and conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires.

 

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Conflicts of interest could arise in the situations described below, among others.

 

Actions taken by our general partner may affect the amount of cash available for distribution to unitholders.

 

The amount of cash that is available for distribution to our unitholders is affected by decisions of our general partner regarding such matters as:

 

    amount and timing of cash expenditures;

 

    assets sales or acquisitions;

 

    borrowings;

 

    the issuance of additional units; and

 

    the creation, reduction or increase of reserves in any quarter.

 

We will reimburse our general partner and its affiliates for expenses.

 

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering staff and support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in any reasonable manner determined by our general partner in its sole discretion. Please read “Certain Relationships and Related Party Transactions.”

 

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

 

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability or our liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

 

Unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

 

Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

 

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

 

Our partnership agreement allows our general partner to determine any amounts to reimburse itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand, and our general partner and its affiliates, on the other, are or will be the result of arm’s-length negotiations.

 

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the units offered in this offering.

 

Our units are subject to our general partner’s limited call right.

 

If at any time our general partner and its affiliates own more than 90% of the units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not

 

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less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. At the completion of this offering and assuming no exercise of the underwriters’ option to purchase additional units, our general partner and its affiliates, including the employee partnership, will own approximately 88.8% of our outstanding units. Please read “Description of Our Partnership Agreement—Limited Call Right.”

 

We may not choose to retain separate counsel for ourselves or for the holders of our units.

 

The attorneys, independent auditors and others who have performed services for us regarding the offering have been retained by our general partner, its affiliates and us and may continue to be retained by our general partner, its affiliates and us after the offering. Attorneys, independent auditors and others who will perform services for us in the future will be selected by our general partner or our audit and conflicts committee and may also perform services for our general partner and its affiliates. We may, but are not required to, retain separate counsel for ourselves or the holders of units in the event of a conflict of interest arising between our general partner and its affiliates, on the one hand, and us or the holders of units, on the other, after the sale of the units offered in this prospectus, depending on the nature of the conflict. We do not intend to do so in most cases.

 

Our general partner’s affiliates may compete with us.

 

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement and subject to certain business opportunity agreements, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Please read “Certain Relationships and Related Party Transactions—Administrative Services Agreement.”

 

Shared Personnel. Our general partner will manage our operations and activities. Under the amended and restated administrative services agreement, EPCO will provide all employees and administrative, 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 and TEPPCO Partners and their affiliates. The services performed by these shared personnel will generally be limited to non-commercial functions, including but not limited to human resources, information technology, financial and accounting services and legal services. We will adopt policies and procedures to protect and prevent inappropriate disclosure by shared personnel of commercial and other non-public information relating to us, Enterprise Products Partners and TEPPCO Partners.

 

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

 

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

 

Fiduciary Duties

 

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, restrict, eliminate or otherwise modify the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

 

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Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. These modifications are detrimental to the unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

 

State law fiduciary duty standards

   Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

Partnership agreement modified standards

   Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.
     Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the audit and conflicts committee of the board of directors of our general partner must be:
    

•      on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

    

•      “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

     If our general partner does not seek approval from the audit and conflicts committee and its board of directors determines that the resolution or course of action taken with respect to

 

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     the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.
     In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

Rights and remedies of unitholders

   The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its fiduciary duties or of the partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

 

In order to become one of our limited partners, a unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

 

We are required to indemnify our general partner and its officers, directors, and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. This indemnification is required unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence. Indemnification is also required for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it met the requirements set forth above. In the opinion of the Commission, indemnification provisions that purport to include indemnification for liabilities arising under the Securities Act are contrary to public policy and are, therefore, unenforceable. If you have questions regarding the fiduciary duties of our general partner, you should consult with your own counsel. Please read “Description of Our Partnership Agreement—Indemnification.”

 

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DESCRIPTION OF OUR UNITS

 

Generally, our units represent limited partner interests that entitle the holders to participate in our cash distributions and to exercise the rights and privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of units and our general partner in and to cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

 

Our outstanding units will be listed on the NYSE under the symbol “EPE.” Any additional units we issue will also be listed on the NYSE.

 

Transfer Agent and Registrar

 

Mellon Investor Services LLC will serve as registrar and transfer agent for the units. We pay all fees charged by the transfer agent for transfers of units, except the following that must be paid by unitholders:

 

    surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

    special charges for services requested by a holder of a common unit; and

 

    other similar fees or charges.

 

There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

 

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

 

Transfer of Units

 

By transfer of our units in accordance with our partnership agreement, each transferee of our units will be admitted as a unitholder with respect to the units transferred when such transfer and admission is reflected in our books and records. Additionally, each transferee of our units:

 

    represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

    automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement;

 

    gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

 

An assignee will become a substituted limited partner of our partnership for the transferred units automatically upon the recording of the transfer on our books and records. The general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

 

We may, at our discretion, treat the nominee holder of a unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 

Units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred units.

 

Until a unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

 

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DESCRIPTION OF OUR PARTNERSHIP AGREEMENT

 

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included as Appendix A in this prospectus.

 

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

    with regard to distributions of available cash, please read “Our Cash Distribution Policy and Restrictions on Distributions;”

 

    with regard to rights of holders of units, please read “Description of Our Units;” and

 

    with regard to allocations of taxable income and other matters, please read “Material Tax Consequences.”

 

Organization and Duration

 

We were organized on April 19, 2005 and have a perpetual existence.

 

Purpose

 

Under our partnership agreement, we are permitted to engage in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law and, in connection therewith, to exercise all of the rights and powers conferred upon us pursuant to the agreements relating to such business activity; provided, however, unless approved by a majority of the independent directors of our general partner’s board of directors, our business will be limited to owning partnership and related interests in Enterprise Products Partners and owning the membership interests in Enterprise Products GP; and provided, further that our general partner shall not cause us to engage, directly or indirectly in any business activity that our general partner determines would cause us or Enterprise Products Partners to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. For a further description of limits on our business, please read “Certain Relationships and Related Party Transactions—Administrative Services Agreement.”

 

Power of Attorney

 

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants the authority to amend, and to make consents and waivers under, our partnership agreement. Please read “—Amendments to Our Partnership Agreement.”

 

Capital Contributions

 

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

 

Limited Liability

 

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

 

    to remove or replace the general partner;

 

    to approve some amendments to the partnership agreement; or

 

    to take other action under the partnership agreement;

 

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constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us and reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

 

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

 

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. While we currently have no operations distinct from Enterprise Products Partners, if in the future, by our ownership in an operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

 

Voting Rights

 

The following is a summary of the unitholder vote required for the matters specified below. In voting their units, affiliates of our general partner will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

 

Issuance of additional units

   No approval right.

Amendment of our partnership agreement

   Certain amendments may be made by our general partner without the approval of our unitholders. Other amendments generally require the approval of a majority of our outstanding units. Please read “—Amendments to Our Partnership Agreement.”

Merger of our partnership or the sale of all or substantially all of our assets

  

A majority of our outstanding units in certain circumstances. Please read “—Merger, Sale or Other Disposition of Assets.”

 

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Dissolution of our partnership

   A majority of our outstanding units. Please read “—Termination or Dissolution.”

Reconstitution of our partnership upon dissolution

   A majority of our outstanding units. Please read “—Termination or Dissolution.”

Withdrawal of our general partner

   Under most circumstances, the approval of a majority of the units, excluding units held by our general partner and its affiliates, is required for the withdrawal of the general partner prior to June 30, 2015 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

Removal of our general partner

   Not less than 66  2 / 3 % of the outstanding units, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of the general partner interest

   Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to (i) an affiliate (other than an individual) or (ii) another entity in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the units, excluding units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to June 30, 2015. Please read “—Transfer of General Partner Interest.”

Transfer of ownership interests in our general partner

   No approval required at any time. Please read “—Transfer of Ownership Interests in Our General Partner.”

 

Issuance of Additional Securities

 

Our partnership agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities that are equal in rank with or junior to our units on terms and conditions established by our general partner in its sole discretion without the approval of our unitholders.

 

It is possible that we will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units we issue will be entitled to share equally with the then-existing holders of units in our cash distributions. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of units in our net assets.

 

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, in the sole discretion of our general partner, may have special voting rights to which units are not entitled or have no voting rights.

 

Upon issuance of additional units or other partnership securities, our general partner will not be required to make additional capital contributions in order to maintain its 0.01% general partner interest in us. Our general

 

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partner and its affiliates have the right, which they may from time to time assign in whole or in part to any of their affiliates, to purchase units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain their percentage interests in us that existed immediately prior to the issuance. Our general partner and its affiliates, including the employee partnership, will hold approximately 88.8% of our outstanding units after this offering. The holders of units will not have preemptive rights to acquire additional units or other partnership interests in us.

 

Amendments to Our Partnership Agreement

 

General

 

Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a majority of our outstanding units.

 

Prohibited Amendments

 

No amendment may be made that would:

 

(1) enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

 

(2) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which may be given or withheld at its option.

 

The provision of our partnership agreement preventing the amendments having the effects described in clauses (1) or (2) above can be amended upon the approval of the holders of at least 90% of the outstanding units.

 

No Unitholder Approval

 

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

 

(1) a change in the name of the partnership, the location of the partnership’s principal place of business, the partnership’s registered agent or its registered office;

 

(2) the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

(3) a change that, in the sole discretion of our general partner, is necessary or advisable for the partnership to qualify or to continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that the partnership will not be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

 

(4) an amendment that is necessary, in the opinion of our counsel, to prevent the partnership or our general partner or its directors, officers, agents or trustees, from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

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(5) any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

(6) an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

 

(7) any amendment that, in the discretion of our general partner, is necessary or advisable for the formation by the partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

 

(8) a change in our fiscal year or taxable year and related changes;

 

(9) certain mergers or conveyances set forth in our partnership agreement; and

 

(10) any other amendments substantially similar to any of the matters described in (1) through (9) above.

 

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner or assignee in connection with a merger or consolidation approved in accordance with our partnership agreement, or if our general partner determines that those amendments:

 

(1) do not adversely affect our limited partners in any material respect;

 

(2) are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

(3) are necessary or advisable to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, compliance with any of which our general partner deems to be in the partnership’s best interest and the best interest of our limited partners;

 

(4) are necessary or advisable for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

(5) are required to effect the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

 

Opinion of Counsel and Unitholder Approval

 

Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments described under “—Amendments to Our Partnership Agreement—No Unitholder Approval.” No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of limited partners constituting not less than the voting requirement sought to be reduced.

 

Merger, Sale or Other Disposition of Assets

 

Our partnership agreement generally prohibits our general partner, without the prior approval of a majority of our outstanding units, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge,

 

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hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval.

 

If conditions specified in our partnership agreement are satisfied, our general partner may merge us or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. The unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a merger or consolidation, a sale of substantially all of our assets or any other transaction or event.

 

Termination or Dissolution

 

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

 

(1) the election of our general partner to dissolve us, if approved by the holders of a majority of our outstanding units, excluding those units held by our general partner and its affiliates;

 

(2) there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

(3) the entry of a decree of judicial dissolution of our partnership; or

 

(4) the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

 

Upon a dissolution under clause (4) above, the holders of a majority of our outstanding units may also elect, excluding any units held by our general partner and its affiliates, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing a successor general partner an entity approved by the holders of a majority of our outstanding units, excluding those units held by our general partner and its affiliates, subject to receipt by us of an opinion of counsel to the effect that:

 

    the action would not result in the loss of limited liability of any limited partner; and

 

    none of our partnership nor the reconstituted limited partnership would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

 

Liquidation and Distribution of Proceeds

 

Upon our dissolution, unless we are reconstituted and continued as a new limited partnership, the person authorized to wind up our affairs (the liquidator) will, acting with all the powers of our general partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets. The proceeds of the liquidation will be applied as follows:

 

    first , towards the payment of all of our creditors and the creation of a reserve for contingent liabilities; and

 

    then , to all partners in accordance with the positive balance in the respective capital accounts.

 

Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to our partners, our general partner may distribute assets in kind to our partners.

 

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Withdrawal or Removal of Our General Partner

 

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2015 without obtaining the approval of a majority of our outstanding units, excluding those held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2015, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. In addition, our general partner may withdraw without unitholder approval upon 90 days’ notice to our limited partners if at least 50% of our outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates.

 

Upon the voluntary withdrawal of our general partner, the holders of a majority of our outstanding units, excluding the units held by the withdrawing general partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of our outstanding units, excluding the units held by the withdrawing general partner and its affiliates, agree to continue our business and to appoint a successor general partner.

 

Our general partner may not be removed unless that removal is approved by not less than 66  2 / 3 % of our outstanding units, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. In addition, if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of such removal, our general partner will have the right to convert its general partner interest into units or to receive cash in exchange for such interests. Any removal of this kind is also subject to the approval of a successor general partner by a majority of our outstanding units, including those held by our general partner and its affiliates. The ownership of more than 33  1 / 3 % of the outstanding units by our general partner and its affiliates would give it the practical ability to prevent its removal. Upon completion of this offering, affiliates of our general partner will own approximately 88.8% of the outstanding units.

 

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest of the departing general partner for a cash payment equal to its fair market value. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner for a cash payment equal to its fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

 

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest will automatically convert into units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

 

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

 

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Transfer of General Partner Interest

 

Except for transfer by our general partner of all, but not less than all, of its general partner interest in us to:

 

    an affiliate of the general partner (other than an individual); or

 

    another entity as part of the merger or consolidation of the general partner with or into another entity or the transfer by the general partner of all or substantially all of its assets to another entity,

 

our general partner may not transfer all or any part of its general partner interest in us to another entity prior to June 30, 2015 without the approval of a majority of the units outstanding, excluding units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume the rights and duties of our general partner, agree to be bound by the provisions of the partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

 

Our general partner and it affiliates may at any time transfer units to one or more persons without unitholder approval.

 

Transfer of Ownership Interests in Our General Partner

 

At any time, Dan Duncan LLC, as the sole member of our general partner, may sell or transfer all or part of its ownership interest in the general partner without the approval of our unitholders.

 

Change of Management Provisions

 

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner as general partner or otherwise change management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner.

 

Limited Call Right

 

If at any time our general partner and its affiliates hold more than 90% of the outstanding limited partner interests of any class, our general partner will have the right, but not the obligation, which it may assign in whole or in part to any of its affiliates or us, to acquire all, but not less than all, of the remaining limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:

 

    the highest cash price paid by either our general partner or any of its affiliates for any limited partners interests of the class purchased within the 90 days preceding the date our general partner first mails notice of its election to purchase the limited partner interests; and

 

    the current market price of the limited partner interests of the class as of the date three days prior to the date that notice is mailed.

 

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or price. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read “Material Tax Consequences—Disposition of Units.”

 

Upon completion of this offering, affiliates of our general partner, including the employee partnership, will own 76,926,591 of our units, representing approximately 88.8% of our outstanding units.

 

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Meetings; Voting

 

Except as described below regarding a person or group owning 20% or more of units then outstanding, unitholders on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Units that are owned by non-citizen assignees will be voted by our general partner and our general partner will distribute the votes on those units in the same ratios as the votes of limited partners on other units are cast.

 

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by our unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

 

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Securities” above. However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

 

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

 

Status as Limited Partner

 

By transfer of units in accordance with our partnership agreement, each transferee of units shall be admitted as a limited partner with respect to the transferred units when such transfer and admission is reflected in our books and records. Except as described under “—Limited Liability,” the units will be fully paid, and unitholders will not be required to make additional contributions.

 

Non-Citizen Assignees; Redemption

 

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee, is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating

 

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distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

 

Indemnification

 

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

(1) our general partner;

 

(2) any departing general partner;

 

(3) any person who is or was an affiliate of our general partner or any departing general partner;

 

(4) any person who is or was an officer, director, member, partner, fiduciary or trustee of any entity described in (1), (2) or (3) above;

 

(5) any person who is or was serving as an officer, director, member, partner, fiduciary or trustee of another person at the request of the general partner or any departing general partner; and

 

(6) any person designated by our general partner.

 

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or loan funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under the partnership agreement.

 

Reimbursement of Expenses

 

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our or Enterprise Products GP’s behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us, our general partner or Enterprise Products GP and expenses allocated to us or otherwise incurred by our general partner in connection with operating our or Enterprise Products GP’s business. The general partner is entitled to determine in good faith the expenses that are allocable to us.

 

Books and Reports

 

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

 

We will furnish or make available to record holders of units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

 

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

 

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Right to Inspect Our Books and Records

 

A limited partner can, for a purpose reasonably related to the limited partner’s interest as a limited partner, upon reasonable demand stating the purpose of such demand and at his own expense, obtain:

 

    a current list of the name and last known address of each partner;

 

    a copy of our tax returns;

 

    information as to the amount of cash and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

 

    copies of our partnership agreement, our certificate of limited partnership, amendments to either of them and powers of attorney which have been executed under our partnership agreement;

 

    information regarding the status of our business and financial condition; and

 

    any other information regarding our affairs as is just and reasonable.

 

Our general partner may, and intends to, keep confidential from the limited partners trade secrets and other information the disclosure of which our general partner believes in good faith is not in our best interest or which we are required by law or by agreements with third parties to keep confidential.

 

Registration Rights

 

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. We are obligated to pay all costs and expenses incidental to any such registration and offering on behalf of our general partner, excluding underwriting discounts and commissions. All costs and expenses of any such registration and offering (other than underwriting discounts and commissions) on behalf of affiliates of our general partner will be paid by such affiliates based on their pro rata participation in such registration and offering. Please read “Units Eligible for Future Sale.”

 

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ENTERPRISE PRODUCTS PARTNERS’ CASH DISTRIBUTION POLICY

 

Following is a description of the relative rights and preferences of holders of Enterprise Products Partners’ common units and Enterprise Products Partners’ general partner in and to cash distributions.

 

Distributions of Available Cash

 

General . Within approximately 45 days after the end of each quarter, Enterprise Products Partners will distribute all of its available cash to unitholders of record on the applicable record date.

 

Definition of Available Cash . Available cash is defined in Enterprise Products Partners’ partnership agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter:

 

    less the amount of cash reserves that is necessary or appropriate in the reasonable discretion of its general partner to:

 

    provide for the proper conduct of Enterprise Products Partners’ business (including reserves for future capital expenditures and for Enterprise Products Partners’ future credit needs);

 

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

 

    provide funds for distributions to unitholders and Enterprise Products Partners’ general partner in respect of any one or more of the next four quarters;

 

    plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under Enterprise Products Partners’ credit facilities and in all cases are used solely for working capital purposes or to pay distributions to its partners.

 

Operating Surplus and Capital Surplus

 

General . Cash distributions are characterized as distributions from either operating surplus or capital surplus. Enterprise Products Partners distributes available cash from operating surplus differently than available cash from capital surplus.

 

Definition of Operating Surplus . Operating surplus is defined in the partnership agreement and generally means:

 

    Enterprise Products Partners’ cash balance on July 31, 1998, the closing date of its initial public offering of common units (excluding $46.5 million to fund certain capital commitments existing at such closing date); plus

 

    all of Enterprise Products Partners’ cash receipts since the closing of its initial public offering, excluding (1) cash from interim capital transactions such as borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other disposition of assets for cash, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of normal retirements or replacements of assets; plus

 

    up to $60.0 million of cash from interim capital transactions; plus

 

    working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

 

    all of Enterprise Products Partners’ operating expenditures since the closing of its initial public offering, including the repayment of working capital borrowings; less

 

    the amount of cash reserved that Enterprise Products GP deems necessary or advisable to provide funds for future operating expenditures.

 

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Definition of Capital Surplus . Capital surplus is generally generated only by:

 

    borrowings (other than borrowings for working capital purposes);

 

    sales of debt and equity securities; and

 

    sales or other dispositions of assets for cash (other than inventory, accounts receivable and other assets disposed of in the ordinary course of business).

 

Characterization of Cash Distributions . To avoid the difficulty of trying to determine whether available cash Enterprise Products Partners distributes is from operating surplus or from capital surplus, all available cash it distributes from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since July 31, 1998 equals the operating surplus as of the end of the quarter prior to such distribution. Any available cash in excess of such amount (irrespective of its source) will be deemed to be from capital surplus and distributed accordingly.

 

If available cash from capital surplus is distributed in respect of each common unit in an aggregate amount per common unit equal to the $11.00 initial public offering price of Enterprise Products Partners’ common units, the distinction between operating surplus and capital surplus will cease, and all distributions of available cash will be treated as if they were from operating surplus. Enterprise Products Partners does not anticipate that there will be significant distributions from capital surplus.

 

Distributions of Available Cash from Operating Surplus

 

Enterprise Products Partners makes distributions of available cash from operating surplus with respect to any quarter in the following manner:

 

    first , 98% to all of its common unitholders, pro rata and 2% to its general partner, until there has been distributed in respect of each unit an amount equal to its minimum quarterly distribution of $0.225; and

 

    thereafter , in the manner described in “—Incentive Distributions” below.

 

Incentive Distributions

 

Incentive distributions represent the right to receive an increasing percentage of Enterprise Products Partners’ quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. For any quarter for which available cash from operating surplus is distributed to Enterprise Products Partners’ common unitholders in an amount equal to the minimum quarterly distribution of $0.225 per unit on all units, then any additional available cash from operating surplus in respect of such quarter will be distributed among Enterprise Products Partners’ common unitholders and its general partner in the following manner:

 

    first , 98% to all of its common unitholders, pro rata, and 2% to its general partner, until the common unitholders have received a total of $0.253 for such quarter in respect of each outstanding unit (the first target distribution);

 

    second , 85% to all of its common unitholders, pro rata, and 15% to its general partner, until the common unitholders have received a total of $0.3085 for such quarter in respect of each outstanding unit (the second target distribution); and

 

    thereafter , 75% to all of its common unitholders, pro rata, and 25% to its general partner.

 

Distributions from Capital Surplus

 

How Distributions from Capital Surplus Will Be Made . Enterprise Products Partners will make distributions of available cash from capital surplus in the following manner:

 

   

first , 98% to all of its common unitholders, pro rata, and 2% to its general partner, until it has distributed, in respect of each outstanding common unit issued in its initial public offering, available

 

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cash from capital surplus in an aggregate amount per common unit equal to the initial unit price of $11.00; and

 

    thereafter , all distributions of available cash from capital surplus will be distributed as if they were from operating surplus.

 

Effect of a Distribution from Capital Surplus . Enterprise Products Partners’ partnership agreement treats a distribution of capital surplus on a common unit as the repayment of the common unit price from its initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per common unit is referred to as the “unrecovered initial common unit price”. Each time a distribution of capital surplus is made on a common unit, the minimum quarterly distribution and the target distribution levels for all units will be reduced in the same proportion as the corresponding reduction in the unrecovered initial common unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for Enterprise Products Partners’ general partner to receive incentive distributions. However, any distribution by Enterprise Products Partners of capital surplus before the unrecovered initial common unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution.

 

Once Enterprise Products Partners distributes capital surplus on a common unit in any amount equal to the unrecovered initial common unit price, it will reduce the minimum quarterly distribution and the target distribution levels to zero and it will make all future distributions of available cash from operating surplus, with 25% being paid to the holders of its common units, as applicable, and 75% to its general partner.

 

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

 

In addition to reductions of the minimum quarterly distribution and target distribution levels made upon a distribution of available cash from capital surplus, if Enterprise Products Partners combines its units into fewer units or subdivides its units into a greater number of units, it will proportionately adjust:

 

    its minimum quarterly distribution;

 

    its target distribution levels; and

 

    its unrecovered initial common unit price.

 

For example, in the event of a two-for-one split of Enterprise Products Partners’ common units (assuming no prior adjustments), the minimum quarterly distribution, each of the target distribution levels and the unrecovered capital of the common units would each be reduced to 50% of its initial level.

 

In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes Enterprise Products Partners to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, then Enterprise Products Partners will reduce its minimum quarterly distribution and its target distribution levels by multiplying the same by one minus the sum of the highest effective federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates. For example, if Enterprise Products Partners became subject to a maximum effective federal, state and local income tax rate of 35%, then its minimum quarterly distribution and its target distribution levels would each be reduced to 65% of their previous levels.

 

Distributions of Cash upon Liquidation

 

If Enterprise Products Partners dissolves in accordance with its partnership agreement, Enterprise Products Partners will sell or otherwise dispose of its assets in a process called a liquidation. Enterprise Products Partners will first apply the proceeds of liquidation to the payment of its creditors in the order of priority provided in its partnership agreement and by law and, thereafter, it will distribute any remaining proceeds to its common unitholders and its general partner in accordance with their respective capital account balances as so adjusted.

 

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

 

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

 

    second , 98% to the holders of its common units, pro rata, and 2% to its general partner, until the capital account for each common unit is equal to the sum of:

 

    the unrecovered capital in respect of such common unit; plus

 

    the amount of the minimum quarterly distribution for the quarter during which its liquidation occurs.

 

    third , 98% to all of its common unitholders, pro rata, and 2% to its general partner, until there has been allocated under this paragraph third an amount per unit equal to:

 

    the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of its existence; less

 

    the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that were distributed 98% to its unitholders, pro rata, and 2% to its general partner for each quarter of its existence;

 

    fourth , 85% to all of its common unitholders, pro rata, and 15% to its general partner, until there has been allocated under this paragraph fourth an amount per unit equal to:

 

    the sum of the excess of the second target distribution per unit over the First Target Distribution per unit for each quarter of its existence; less

 

    the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that were distributed 85% to its unitholders, pro rata, and 15% to its general partner for each quarter of its existence; and

 

    thereafter , 75% to all of its common unitholders, pro rata, and 25% to its general partner.

 

Manner of Adjustments for Losses . Upon Enterprise Products Partners’ liquidation, any loss will generally be allocated to its general partner and its unitholders as follows:

 

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

 

    thereafter , 100% to its general partner.

 

Adjustments to Capital Accounts. In addition, interim adjustments to capital accounts will be made at the time Enterprise Products Partners issues additional partnership interests or makes 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 Enterprise Products Partners’ common unitholders and its general partner in the same manner as gain or loss is allocated upon liquidation. In the event that positive interim adjustments are made to the capital accounts, any subsequent negative adjustments to the capital accounts resulting from the issuance of additional partnership interests in Enterprise Products Partners, distributions of property by Enterprise Products Partners, or upon Enterprise Products Partners’ liquidation, will be allocated in a manner which results, to the extent possible, in the capital account balances of Enterprise Products Partners’ general partner equaling the amount that would have been the general partner’s capital account balances if no prior positive adjustments to the capital accounts had been made.

 

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MATERIAL PROVISIONS OF

ENTERPRISE PRODUCTS PARTNERS’ PARTNERSHIP AGREEMENT

 

The following is a summary of material provisions of Enterprise Products Partners’ partnership agreement. For more information on distributions of Enterprise Products Partners’ available cash, please read “Enterprise Products Partners’ Cash Distribution Policy.”

 

Purpose

 

Enterprise Products Partners’ purpose under its partnership agreement is to serve as a partner of Enterprise Products Partners’ operating partnership and to engage in any business activities that may be engaged in by Enterprise Products Partners’ operating partnership or that are approved by Enterprise Products Partners’ general partner. The partnership agreement of Enterprise Products Partners’ operating partnership provides that it may engage in any activity that was engaged in by Enterprise Products Partners’ predecessors at the time of Enterprise Products Partners’ initial public offering or reasonably related thereto and any other activity approved by Enterprise Products Partners’ general partner.

 

Voting Rights

 

Enterprise Products Partners unitholders do not have voting rights except with respect to the following matters, for which Enterprise Products Partners’ partnership agreement requires the approval of the holders of a majority of the units, unless otherwise indicated:

 

    the merger of Enterprise Products Partners or a sale, exchange or other disposition of all or substantially all of its assets;

 

    the withdrawal of Enterprise Products Partners’ general partner (generally requires a majority of the units outstanding, excluding units held by Enterprise Products Partners’ general partner and its affiliates, prior to December 31, 2008);

 

    the removal of Enterprise Products Partners’ general partner (requires 64% of the outstanding units, including units held by Enterprise Products Partners’ general partner and its affiliates);

 

    the election of a successor to Enterprise Products Partners’ general partner;

 

    the dissolution of Enterprise Products Partners or the reconstitution of Enterprise Products Partners upon dissolution;

 

    approval of certain actions of Enterprise Products Partners’ general partner (including the transfer by the general partner of its general partner interest under certain circumstances); and

 

    certain amendments to Enterprise Products Partners’ partnership agreement, including any amendment that would cause Enterprise Products Partners to be treated as an association taxable as a corporation.

 

Under Enterprise Products Partners’ partnership agreement, Enterprise Products Partners’ general partner is generally permitted to effect, without the approval of Enterprise Products Partners’ unitholders, amendments to the partnership agreement that do not adversely affect Enterprise Products Partners’ unitholders.

 

Issuance of Additional Securities

 

Enterprise Products Partners’ partnership agreement authorizes it to issue an unlimited number of additional limited partner interests and other equity securities that are equal in rank with or junior to its common units on terms and conditions established by its general partner in its general partner’s sole discretion without the approval of any limited partners.

 

It is possible that Enterprise Products Partners will fund acquisitions through the issuance of additional common units or other equity securities. Holders of any additional common units Enterprise Products Partners

 

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issues will be entitled to share equally with the then-existing holders of its common units in its cash distributions. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of common units in Enterprise Products Partners’ net assets.

 

In accordance with Delaware law and the provisions of its partnership agreement, Enterprise Products Partners may also issue additional partnership interests that, in the sole discretion of its general partner, may have special voting rights to which common units are not entitled.

 

Enterprise Products Partners’ general partner has the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other equity securities whenever, and on the same terms that, Enterprise Products Partners issues those securities to persons other than its general partner and its affiliates, to the extent necessary to maintain their percentage interests in Enterprise Products Partners that existed immediately prior to the issuance. The holders of Enterprise Products Partners’ common units will not have preemptive rights to acquire additional common units or other partnership interests in it.

 

Amendments to Enterprise Products Partners’ Partnership Agreement

 

Amendments to Enterprise Products Partners’ partnership agreement may be proposed only by Enterprise Products Partners’ general partner. Any amendment that materially and adversely affects the rights or preferences of any type or class of limited partner interests in relation to other types or classes of limited partner interests or Enterprise Products Partners’ general partner interest will require the approval of at least a majority of the type or class of limited partner interests or general partner interests so affected. However, in some circumstances, more particularly described in Enterprise Products Partners’ partnership agreement, Enterprise Products Partners’ general partner may make amendments to Enterprise Products Partners’ partnership agreement without the approval of Enterprise Products Partners’ limited partners or assignees to reflect:

 

    a change in Enterprise Products Partners’ names, the location of its principal place of business, its registered agent or its registered office;

 

    the admission, substitution, withdrawal or removal of partners;

 

    a change to qualify or continue Enterprise Products Partners’ qualification as a limited partnership or a partnership in which its limited partners have limited liability under the laws of any state or to ensure that neither Enterprise Products Partners, its operating partnership, nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

 

    a change that does not adversely affect Enterprise Products Partners’ limited partners in any material respect;

 

    a change to (i) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute or (ii) facilitate the trading of Enterprise Products Partners’ limited partner interests or comply with any rule, regulation, guideline or requirement of any national securities exchange on which its limited partner interests are or will be listed for trading;

 

    a change in Enterprise Products Partners’ fiscal year or taxable year and any changes that are necessary or advisable as a result of a change in its fiscal year or taxable year;

 

    an amendment that is necessary to prevent Enterprise Products Partners, or its general partner or its general partner’s directors, officers, trustees or agents from being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended;

 

    an amendment that is necessary or advisable in connection with the authorization or issuance of any class or series of Enterprise Products Partners’ securities;

 

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    any amendment expressly permitted in Enterprise Products Partners’ partnership agreement to be made by its general partner acting alone;

 

    an amendment effected, necessitated or contemplated by a merger agreement approved in accordance with its partnership agreement;

 

    an amendment that is necessary or advisable to reflect, account for and deal with appropriately Enterprise Products Partners’ formation of, or investment in, any corporation, partnership, joint venture, limited liability company or other entity other than its operating partnership, in connection with its conduct of activities permitted by its partnership agreement;

 

    a merger or conveyance to effect a change in Enterprise Products Partners’ legal form; or

 

    any other amendments substantially similar to the foregoing.

 

Merger, Sale or Other Disposition of Assets

 

Enterprise Products Partners’ general partner is generally prohibited, without the prior approval of the holders of at least a majority of the outstanding common units (excluding common units held by the general partner and its affiliates), from causing Enterprise Products Partners to, among other things, sell, exchange or otherwise dispose of all or substantially all of its assets in a single transaction or a series of related transactions (including by way of merger, consolidation or other combination) or approving on behalf of Enterprise Products Partners the sale, exchange or other disposition of all or substantially all of the assets of its operating partnership; provided that its general partner may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of Enterprise Products Partners without such approval. Enterprise Products Partners’ general partner may also sell all or substantially all of Enterprise Products Partners’ assets pursuant to a foreclosure or other realization upon the foregoing encumbrances without such approval. Furthermore, provided that certain conditions are satisfied, the Enterprise Products Partners’ general partner may merge Enterprise Products Partners or any member of its partnership group into, or convey some or all of the partnership group’s assets to, a newly-formed entity if the sole purpose of such merger or conveyance is to effect a mere change in the legal form of Enterprise Products Partners into another limited liability entity. Enterprise Products Partners’ unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a merger or consolidation of the Enterprise Products Partners, a sale of substantially all of Enterprise Products Partners’ assets or any other transaction or event.

 

Termination or Dissolution

 

Enterprise Products Partners will continue as a limited partnership until terminated under its partnership agreement. Enterprise Products Partners will dissolve upon:

 

(1) the election of Enterprise Products Partners’ general partner to dissolve Enterprise Products Partners, if approved by the holders of a majority of Enterprise Products Partners’ outstanding common units, excluding those common units held by Enterprise Products Partners’ general partner and its affiliates;

 

(2) the sale, exchange or other disposition of all or substantially all of Enterprise Products Partners assets and properties and those of its subsidiaries;

 

(3) the entry of a decree of judicial dissolution of Enterprise Products Partners; or

 

(4) the withdrawal or removal of Enterprise Products Partners’ general partner or any other event that results in its ceasing to be Enterprise Products Partners’ general partner other than by reason of a transfer of its general partner interest in accordance with Enterprise Products Partners’ partnership agreement or withdrawal or removal following approval and admission of a successor.

 

Upon a dissolution under clause (4) above, the holders of a majority of Enterprise Products Partners’ common outstanding units may also elect, excluding those common units held by Enterprise Products Partners’

 

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general partner and its affiliates, within specific time limitations, to reconstitute Enterprise Products Partners and continue its business on the same terms and conditions described in its partnership agreement by forming a new limited partnership on terms identical to those in Enterprise Products Partners’ partnership agreement and having as general partner an entity approved by the holders of a majority of Enterprise Products Partners’ outstanding common units, excluding those common units held by Enterprise Products Partners’ general partner and its affiliates, subject to receipt by Enterprise Products Partners of an opinion of counsel to the effect that:

 

    the action would not result in the loss of limited liability of any limited partner; and

 

    none of the partnership, the reconstituted limited partnership, Enterprise Products Partners’ operating partnership nor any of its other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

 

Liquidation and Distribution of Proceeds

 

Upon Enterprise Products Partners’ dissolution, unless it is reconstituted and continued as a new limited partnership, the person authorized to wind up Enterprise Products Partners’ affairs (the liquidator) will, acting with all the powers of Enterprise Products Partners’ general partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate Enterprise Products Partners’ assets. The proceeds of the liquidation will be applied as follows:

 

    first , towards the payment of all of Enterprise Products Partners’ creditors and the creation of a reserve for contingent liabilities; and

 

    then , to all partners in accordance with the positive balance in the respective capital accounts.

 

Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of Enterprise Products Partners’ assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to Enterprise Products Partners’ partners, Enterprise Products Partners’ general partner may distribute assets in kind to Enterprise Products Partners’ partners.

 

Withdrawal or Removal of Enterprise Products Partners’ General Partner

 

Enterprise Products Partners’ general partner has agreed not to withdraw voluntarily as Enterprise Products Partners’ general partner prior to December 31, 2008 without obtaining the approval of the holders of a majority of Enterprise Products Partners’ outstanding common units, excluding those held by Enterprise Products Partners’ general partner and its affiliates, and furnishing an opinion of counsel stating that such withdrawal (following the selection of the successor general partner) would not result in the loss of the limited liability of any of Enterprise Products Partners’ limited partners or of a member of Enterprise Products Partners’ operating partnership or cause Enterprise Products Partners or its operating partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such).

 

On or after December 31, 2008, Enterprise Products Partners’ general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of Enterprise Products Partners’ partnership agreement. In addition, Enterprise Products Partners’ general partner may withdraw without unitholder approval upon 90 days’ notice to Enterprise Products Partners’ limited partners if at least 50% of Enterprise Products Partners’ outstanding common units are held or controlled by one person and its affiliates other than its general partner and its affiliates.

 

Upon the voluntary withdrawal of Enterprise Products Partners’ general partner, the holders of a majority of Enterprise Products Partners’ outstanding common units, excluding the common units held by the withdrawing general partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained,

 

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Enterprise Products Partners will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of its outstanding units, excluding the common units held by the withdrawing general partner and its affiliates, agree to continue Enterprise Products Partners’ business and to appoint a successor general partner.

 

Enterprise Products Partners’ general partner may not be removed unless that removal is approved by the vote of the holders of not less than 64% of Enterprise Products Partners’ outstanding units, including units held by its general partner and its affiliates, and Enterprise Products Partners receives an opinion of counsel regarding limited liability and tax matters. In addition, if Enterprise Products Partners’ general partner is removed as Enterprise Products Partners’ general partner under circumstances where cause does not exist and units held by Enterprise Products Partners’ general partner and its affiliates are not voted in favor of such removal, Enterprise Products Partners’ general partner will have the right to convert its general partner interest into common units or to receive cash in exchange for such interests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as Enterprise Products Partners’ general partner. Any removal of this kind is also subject to the approval of a successor general partner by the vote of the holders of a majority of Enterprise Products Partners’ outstanding common units, including those held by its general partner and its affiliates.

 

While Enterprise Products Partners’ partnership agreement limits the ability of Enterprise Products Partners’ general partner to withdraw, it allows the general partner interest to be transferred to an affiliate or to a third party in conjunction with a merger or sale of all or substantially all of the assets of Enterprise Products Partners’ general partner. In addition, Enterprise Products Partners’ partnership agreement expressly permits the sale, in whole or in part, of the ownership of Enterprise Products Partners’ general partner. Enterprise Products Partners’ general partner may also transfer, in whole or in part, the common units it owns.

 

Transfer of General Partner Interests

 

Except for a transfer by Enterprise Products Partners’ general partner of all, but not less than all, of its general partner interest in Enterprise Products Partners and its operating partnership to:

 

(a) an affiliate of the general partner; or

 

(b) another person in connection with the merger or consolidation of the general partner with or into another person or the transfer by such general partner of all or substantially all of its assets to another person;

 

the general partner may not transfer all or any part of its general partner interest in Enterprise Products Partners or its operating partnership to another person prior to June 30, 2008, without the approval of the holders of at least a majority of the outstanding common units (excluding common units held by the general partner and its affiliates); provided that, in each case, such transferee assumes the rights and duties of the general partner to whose interest such transferee has succeeded, agrees to be bound by the provisions of the partnership agreement, furnishes an opinion of counsel regarding limited liability and tax matters and agrees to acquire all (or the appropriate portion thereof, as applicable) of the general partner’s interest in Enterprise Products Partners’ operating partnership and agrees to be bound by the provisions of the operating partnership’s partnership agreement. At any time, the members of the general partner may sell or transfer all or part of their interest in the general partner to an affiliate or a third party without the approval of the unitholders.

 

Change of Management Provisions

 

Enterprise Products Partners’ partnership agreement contains the following specific provisions that are intended to discourage a person or group from attempting to remove Enterprise Products Partners’ general partner or otherwise change management:

 

    any units held by a person that owns 20% or more of any class of Enterprise Products Partners’ units then outstanding, other than its general partner and its affiliates, cannot be voted on any matter; and

 

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    the partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about Enterprise Products Partners’ operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

 

Limited Call Right

 

If at any time Enterprise Products Partners’ general partner and its affiliates own 85% or more of the issued and outstanding limited partner interests of any class, Enterprise Products Partners’ general partner will have the right to purchase all, but not less than all, of the outstanding limited partner interests of that class that are held by non-affiliated persons. The record date for determining ownership of the limited partner interests would be selected by Enterprise Products Partners’ general partner on at least 10 but not more than 60 days’ notice. The purchase price in the event of a purchase under these provisions would be the greater of (1) the current market price (as defined in Enterprise Products Partners’ partnership agreement) of the limited partner interests of the class as of the date three days prior to the date that notice is mailed to the limited partners as provided in the partnership agreement and (2) the highest cash price paid by Enterprise Products Partners’ general partner or any of its affiliates for any limited partner interest of the class purchased within the 90 days preceding the date Enterprise Products Partners’ general partner mails notice of its election to purchase the units.

 

As of July 15, 2005, Enterprise Products Partners’ general partner and other affiliates of Dan L. Duncan owned 143,556,513 common units of Enterprise Products Partners, representing an aggregate 37.3% of the outstanding common units of Enterprise Products Partners.

 

Reimbursement of Expenses

 

Enterprise Products Partners’ partnership agreement requires it to reimburse its general partner for all direct and indirect expenses it incurs or payments it makes on Enterprise Products Partners’ behalf and all other expenses allocable to Enterprise Products Partners or otherwise incurred by its general partner in connection with operating Enterprise Products Partners’ business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for Enterprise Products Partners or on its behalf and expenses allocated to its general partner by its affiliates. Enterprise Products Partners’ general partner is entitled to determine in good faith the expenses that are allocable to Enterprise Products Partners.

 

Indemnification

 

Under its partnership agreement, in most circumstances, Enterprise Products Partners will indemnify Enterprise Products Partners’ general partner, its general partner’s affiliates and their officers and directors to the fullest extent permitted by law, from and against all losses, claims or damages any of them may suffer by reason of their status as general partner, officer or director, as long as the person seeking indemnity acted in good faith and in a manner believed to be in or not opposed to Enterprise Products Partners’ best interest. Any indemnification under these provisions will only be out of Enterprise Products Partners’ assets. Enterprise Products Partners’ general partner shall not be personally liable for, or have any obligation to contribute or loan funds or assets to Enterprise Products Partners to enable Enterprise Products Partners to effectuate any indemnification. Enterprise Products Partners is authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for its activities, regardless of whether it would have the power to indemnify the person against liabilities under its partnership agreement.

 

Registration Rights

 

Under its partnership agreement, Enterprise Products Partners has agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership securities proposed to be sold by its general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. Enterprise Products Partners is obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions.

 

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UNITS ELIGIBLE FOR FUTURE SALE

 

After the sale of the units offered by this prospectus, affiliates of our general partner, including the employee partnership, will hold an aggregate of 76,926,591 of our units, representing approximately 88.8% of our outstanding units. The sale of these units could have an adverse impact on the price of the units or on any trading market that may develop.

 

The units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

    1% of the total number of the securities outstanding; or

 

    the average weekly reported trading volume of the units for the four calendar weeks prior to the sale.

 

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements, and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his units for at least two years, would be entitled to sell units under Rule 144 without regard to the current public information requirements, volume limitations, manner of sale provisions, and notice requirements of Rule 144.

 

The partnership agreement provides that we may issue an unlimited number of limited partner interests without a vote of the unitholders. Such units may be issued on the terms and conditions established by our general partner. Any issuance of additional units would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to, and market price of, units then outstanding. Please read “Description of Our Partnership Agreement—Issuance of Additional Securities.”

 

Under the partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and commissions. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

 

We, the officers and directors of our general partner, our principal unitholders and participants in our directed unit program who are affiliates of us have agreed not to sell any units they beneficially own for a period of 180 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

 

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MATERIAL TAX CONSEQUENCES

 

This section is a discussion of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., tax counsel to the general partner and us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Enterprise GP Holdings and Enterprise Products GP.

 

The following discussion does not comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of units.

 

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.

 

Except with respect to very limited issues, no ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the units and the prices at which units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

 

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election”).

 

Partnership Status

 

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

 

Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with

 

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respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof, including our allocable share of such income from Enterprise Products Partners. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 10% of our current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.

 

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and Enterprise Products GP will be disregarded as an entity separate from us for federal income tax purposes.

 

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and the general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:

 

    Neither we, nor Enterprise Products GP, will elect to be treated as a corporation; and

 

    For each taxable year, more than 90% of our gross income will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

 

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

 

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. Moreover, if Enterprise Products Partners were taxable as a corporation in any given year, our share of Enterprise Products Partners’ items of income, gain, loss and deduction would not be passed through to us, and Enterprise Products Partners would pay tax on its income at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his units, or taxable capital gain, after the unitholder’s tax basis in his units is reduced to zero. Accordingly, taxation of either us or Enterprise Products Partners as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

 

The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we and Enterprise Products Partners will be classified as a partnership for federal income tax purposes.

 

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Limited Partner Status

 

Unitholders who have become limited partners of Enterprise GP Holdings will be treated as partners of Enterprise GP Holdings for federal income tax purposes. Unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will also be treated as partners of Enterprise GP Holdings for federal income tax purposes.

 

A beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

 

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their status as partners in Enterprise GP Holdings for federal income tax purposes.

 

Tax Consequences of Unit Ownership

 

Flow-through of Taxable Income . We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

 

Treatment of Distributions . Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the units, taxable in accordance with the rules described under “—Disposition of Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

 

A decrease in a unitholder’s percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

 

Ratio of Taxable Income to Distributions . We estimate that a purchaser of units in this offering who owns those units from the date of closing of this offering through December 31, 2008, will be allocated an amount of federal taxable income for that period that will be 10% or less of the cash distributed with respect to that period. We anticipate that after the taxable year ending December 31, 2008, the ratio of allocable taxable income to cash

 

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distributions to the unitholders will increase. Moreover, if Enterprise Products Partners is successful in increasing distributable cash flow over time, our income allocations from incentive distribution rights will increase, and, therefore, our ratio of taxable income to cash distributions will further increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual ratio of taxable income to distributions could be higher or lower, and any differences could be material and could materially affect the value of the units.

 

Basis of Units . A unitholder’s initial tax basis for his units will be the amount he paid for the units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of Units—Recognition of Gain or Loss.”

 

Limitations on Deductibility of Losses . The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

 

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

 

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally corporate or partnership activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

 

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A unitholder’s share of our net income may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

 

Limitations on Interest Deductions . The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

    interest on indebtedness properly allocable to property held for investment;

 

    our interest expense attributed to portfolio income; and

 

    the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

 

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

 

Entity Level Collections . If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

 

Allocation of Income, Gain, Loss and Deduction . In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

 

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed to us by the general partner and its affiliates, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder purchasing units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

 

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the

 

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fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

 

    his relative contributions to us;

 

    the interests of all the partners in profits and losses;

 

    the interest of all the partners in cash flow; and

 

    the rights of all the partners to distributions of capital upon liquidation.

 

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

 

Treatment of Short Sales . A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:

 

    any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

 

    any cash distributions received by the unitholder as to those units would be fully taxable; and

 

    all of these distributions would appear to be ordinary income.

 

Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where units are loaned to a short seller to cover a short sale of units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

 

Alternative Minimum Tax . Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

 

Tax Rates . In general, the highest effective United States federal income tax rate for individuals is currently 35.0% and the maximum United States federal income tax rate for net capital gains of an individual is currently 15.0% if the asset disposed of was held for more than 12 months at the time of disposition.

 

Section 754 Election . We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a

 

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unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

 

Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we will adopt), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury Regulations. Please read “—Uniformity of Units.”

 

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 of the Internal Revenue Code but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.”

 

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.

 

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets or the tangible assets owned by Enterprise Products Partners to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

 

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Tax Treatment of Operations

 

Accounting Method and Taxable Year . We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

 

Tax Basis, Depreciation and Amortization . The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The tax basis of our assets owned by us at the time of this offering will be greater to the extent such assets have been recently acquired. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by the general partner and its affiliates. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

 

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

 

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Units—Recognition of Gain or Loss.”

 

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

 

Valuation and Tax Basis of Our Properties . The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

 

Disposition of Units

 

Recognition of Gain or Loss . Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

 

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Prior distributions from us in excess of cumulative net taxable income for a unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than his original cost.

 

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own or Enterprise Products Partners owns. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

 

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

 

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

    a short sale;

 

    an offsetting notional principal contract; or

 

    a futures or forward contract with respect to the partnership interest or substantially identical property.

 

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

 

Allocations Between Transferors and Transferees . In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is

 

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recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

 

The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

 

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

 

Notification Requirements . A purchaser of units who purchases units from another unitholder is required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may lead to the imposition of substantial penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker.

 

Constructive Termination . We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

 

Uniformity of Units

 

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

 

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section

 

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743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Units—Recognition of Gain or Loss.”

 

Tax-Exempt Organizations and Other Investors

 

Ownership of units by employee benefit plans, other tax-exempt organizations, regulated investment companies, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

 

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

 

A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income. However, recent legislation also includes net income derived from the ownership of an interest in a “qualified publicly traded partnership” as qualified income to a regulated investment company. We expect that we will meet the definition of a qualified publicly traded partnership and will therefore be considered a qualifying income source for mutual funds. However, this legislation is only effective for taxable years of mutual funds beginning after October 22, 2004.

 

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

 

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

 

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign

 

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unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

 

Administrative Matters

 

Information Returns and Audit Procedures . We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

 

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

 

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement names EPE Holdings, LLC as our Tax Matters Partner.

 

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

 

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

 

Nominee Reporting . Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

    the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

    whether the beneficial owner is:

 

(1) a person that is not a United States person;

 

(2) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

(3) a tax-exempt entity;

 

    the amount and description of units held, acquired or transferred for the beneficial owner; and

 

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    specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

 

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

 

Accuracy related and Assessable Penalties . An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

 

A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

(1) for which there is, or was, “substantial authority”; or

 

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

 

More stringent rules, including additional penalties and extended statutes of limitations, may apply as a result of our participation in “listed transactions” or “reportable transactions with a significant tax avoidance purpose.” While we do not anticipate participating in such transactions, if any item of income, gain, loss or deduction included in the distributive shares of unitholders for a given year might result in an “understatement” of income relating to such a transaction, we will disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for penalties.

 

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

 

State, Local, Foreign and Other Tax Considerations

 

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we or Enterprise Products Partners do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many other jurisdictions in which we may do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax

 

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liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity Level Collections.” Based on current law and our estimate of our future operations, the general partner anticipates that any amounts required to be withheld will not be material.

 

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

 

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INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS

 

An investment in our units by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA, and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

 

    whether the investment is prudent under Section 404(a)(l)(B) of ERISA;

 

    whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(l)(C) of ERISA; and

 

    whether the investment will result in recognition of unrelated business taxable income (please read “Material Tax Consequences—Tax-Exempt Organizations and Other Investors”) by the plan and, if so, the potential after-tax investment return.

 

In addition, the person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in our units is authorized by the appropriate governing instrument and is a proper investment for the plan.

 

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan. Therefore, a fiduciary of an employee benefit plan or an IRA accountholder that is considering an investment in our units should consider whether the entity’s purchase or ownership of such units would or could result in the occurrence of such a prohibited transaction.

 

In addition to considering whether the purchase of units is or could result in a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in our units, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of the plan and our operations would be subject to the regulatory restrictions of ERISA, including fiduciary standard and its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

 

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

 

    the equity interests acquired by employee benefit plans are publicly offered securities; i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

 

    the entity is an “operating company;” i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries; or

 

    there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest, disregarding some interests held by our general partner, its affiliates, and some other persons, is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

 

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in the first bullet point above.

 

Plan fiduciaries contemplating a purchase of units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

 

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UNDERWRITING

 

Citigroup Global Markets Inc. and Lehman Brothers Inc. are acting as joint book-running managers of the offering and representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of units set forth opposite the underwriter’s name.

 

Underwriter


   Number of Units

Citigroup Global Markets Inc.

    

Lehman Brothers Inc.

    
      
      
      
    

Total

   12,000,000
    

 

The underwriting agreement provides that the obligations of the underwriters to purchase the units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the units (other than those covered by their option to purchase additional units described below) if they purchase any of the units.

 

The underwriters propose to offer some of the units directly to the public at the public offering price set forth on the cover page of the prospectus and some of the units to dealers at the public offering price less a concession not to exceed $             per unit. The underwriters may allow, and dealers may reallow, a concession not to exceed $              per unit on sales to other dealers. If all of the units are not sold at the initial offering price, the representatives may change the public offering price and the other selling terms. The underwriters have informed us that they do not intend to confirm sales to discretionary accounts without prior approval of the customer and do not intend sales to such discretionary accounts to exceed 5% of the total number of our units offered by them.

 

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase, from time to time, in whole or in part, up to 1,516,667 additional units at the public offering price less the underwriting discount. This option may be exercised if the underwriters sell more than 12,000,000 units in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional units approximately proportionate to that underwriter’s initial purchase commitment.

 

We, our general partner, the officers and directors of our general partner, our principal beneficial unitholders, the employee partnership and participants in our directed unit program have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citigroup Global Markets Inc. and Lehman Brothers Inc., dispose of or hedge any of our units or any securities convertible into or exchangeable for our units. The restrictions described in this paragraph do not apply to the issuance and sale of units by us to the underwriters pursuant to the underwriting agreement.

 

Citigroup Global Markets Inc. and Lehman Brothers Inc. in their discretion may release any of the securities subject to these lock-up agreements at any time without notice. Factors in deciding whether to release these units may include the length of time before the particular lock-up expires, the number of units involved, historical trading volumes of our units and whether the person seeking the release is an officer, director or affiliate of us or our general partner.

 

The 180-day restricted period described in the preceding paragraph will be extended if:

 

    during the last 17 days of the 180-day restricted period we or Enterprise Products Partners issue an earnings release or announce material news or a material event; or

 

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    prior to the expiration of the 180-day restricted period, we or Enterprise Products Partners announce that we or Enterprise Products Partners will release earnings results during the 16-day period beginning on the last day of the 180-day restricted period,

 

in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or event.

 

At our request, the underwriters have reserved $51 million of units (or an estimated 1,888,889 units) to offer to EPCO Holdings at the initial public offering price. EPCO Holdings intends to contribute these units to EPE Unit L.P., which we refer to as the employee partnership. The underwriters will receive no discount or commission on these units offered to EPCO Holdings. Please read “Management—Enterprise GP Holdings—Executive Officer Compensation—Employee Partnership.”

 

At our request, the underwriters have reserved up to an additional 10% of the total units offered by this prospectus, excluding the 1,888,889 units to be offered to the employee partnership, as part of our directed unit program. These units will be offered at the initial public offering price to certain persons who are directors, employees or officers or who are otherwise associated with us and will include $5 million of units (or an estimated 185,185 units) offered to O.S. Andras, a director of Enterprise Products GP, and $10 million of units (or an estimated 370,370 units) offered to entities controlled by Dan L. Duncan, the Chairman of our general partner and EPCO. The number of units available for sale to the general public will be reduced by the units purchased by EPCO Holdings as described above and by the units purchased by the participants in our directed unit program. Any units not purchased by EPCO Holdings or purchased in the directed unit program will be offered by the underwriters to the general public on the same basis as all other units offered to the public. The underwriters will not receive any discount or commission on the aggregate $15 million of units offered to O.S. Andras and the entities controlled by Dan L. Duncan in our directed unit program. We and our general partner have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sale of the units to EPCO Holdings and the participants in the directed unit program. Certain additional officers, directors and related parties purchasing units in the directed unit program, including             , may each purchase units with a value in excess of $60,000.

 

Prior to this offering, there has been no public market for our units. Consequently, the initial public offering price for the units was determined by negotiations between our general partner, the representatives and the qualified independent underwriter. Among the factors considered in determining the initial public offering price were the information set forth in this prospectus and otherwise available to the underwriters, including Enterprise Products Partners’ historical performance and the market price for Enterprise Products Partners’ common units (which trade on the NYSE under the symbol “EPD”), market conditions for initial public offerings, the history and prospects for the industry in which we compete, the ability of our management, our prospects for future earnings, the present state of our development and our current financial condition, the general condition of the securities market at the time of this offering and the recent market prices of, and the demand for, publicly traded equity securities of comparable entities. We cannot assure you, however, that the prices at which the units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our units will develop and continue after this offering.

 

We have applied to have our units listed on the New York Stock Exchange under the symbol “EPE.” The underwriters have undertaken to sell our units to a minimum of 2,000 beneficial owners in round lots of 100 or more units to meet the New York Stock Exchange distribution requirements for trading.

 

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional units.

 

     Paid by Enterprise GP Holdings L.P.

     No Exercise

   Full Exercise

Per unit

   $                 $             

Total

   $                 $             

 

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In connection with the offering, the underwriters may purchase and sell units in the open market. These transactions may include short sales, syndicate covering transactions and stabilizing transactions. Short sales involve syndicate sales of units in excess of the number of units to be purchased by the underwriters in the offering, which creates a syndicate short position. “Covered” short sales are sales of units made in an amount up to the number of units represented by the underwriters’ option to purchase additional units from us. In determining the source of units to close out the covered syndicate short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase units through their option to purchase additional units. Transactions to close out the covered syndicate short position involve either purchases of the units in the open market after the distribution has been completed or the exercise of their option to purchase additional units. The underwriters may also make “naked” short sales of units in excess of their option to purchase additional units. The underwriters must close out any naked short position by purchasing units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of bids for or purchases of units in the open market while the offering is in progress.

 

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when an underwriter repurchases units originally sold by that syndicate member in order to cover syndicate short positions or make stabilizing purchases.

 

Any of these activities may have the effect of preventing or retarding a decline in the market price of the units. They may also cause the price of the units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on the New York Stock Exchange or in the over-the-counter market, or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

 

We estimate that our portion of the total expenses of this offering will be approximately $3.5 million, which includes an aggregate structuring fee of $1.0 million to be paid to Citigroup Global Markets Inc. and Lehman Brothers Inc. for valuation, analysis and structuring of our partnership.

 

The underwriters have performed investment and commercial banking and advisory services for us, Enterprise Products Partners and our affiliates from time to time for which they have received customary fees and expenses. The underwriters may, from time to time, engage in transactions with and perform services for us, Enterprise Products Partners and our affiliates in the ordinary course of their business. Citigroup Global Markets Inc. and Lehman Brothers Inc. served as underwriters in connection with Enterprise Products Partners’ public offering of 17,250,000 of its common units in February 2005 and were also initial purchasers in the Operating Partnership’s private placement of $500 million in principal amount of its senior notes in March 2005.                      served as underwriters in connection with the Operating Partnership’s public offering of $500 million in principal amount of its senior notes in May 2005.

 

Additionally, affiliates of Citigroup Global Markets Inc. and Lehman Brothers Inc. will be lenders under our new credit facility, and are lenders under Enterprise Products Partners’ multi-year revolving credit facility and EPCO Holdings’ new credit facility. The EPCO Holdings credit facility will be used to repay a portion of EPCO’s 364-day bridge loan under which affiliates of Citigroup Global Markets Inc. and Lehman Brothers Inc. are also lenders. The remaining portion of the indebtedness outstanding under EPCO’s 364-day bridge loan will be repaid with the indebtedness incurred by us under our new credit facility. All of the proceeds of this offering will be used to repay a portion of the indebtedness outstanding under our new credit facility. Please read “Use of Proceeds.”

 

Because affiliates of Citigroup Global Markets Inc. and Lehman Brothers Inc. will be lenders under our new credit facility and will directly receive more than 10% of the net proceeds of this offering when we repay a portion of that facility, they may be deemed to have a “conflict of interest” with us under Rule 2710(h)(1) of the

 

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National Association of Securities Dealers, Inc. When a NASD member with a conflict of interest participates as an underwriter in a public offering, that rule requires that the initial public offering price may be no higher than that recommended by a “qualified independent underwriter,” as defined by the NASD. In accordance with this rule,              has assumed the responsibilities of acting as a qualified independent underwriter. In its role as a qualified independent underwriter,              has performed a due diligence investigation and participated in the preparation of this prospectus and the registration statement of which this prospectus is a part.                      will not receive any additional fees for serving as qualified independent underwriter in connection with this offering. We and our general partner have agreed to indemnify              against liabilities incurred in connection with acting as a qualified independent underwriter, including liabilities under the Securities Act.

 

Because the National Association of Securities Dealers, Inc. views the units offered by this prospectus as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. Investor suitability with respect to the units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

 

If you purchase any units offered in this prospectus you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

 

A prospectus in electronic format may be made available by one or more of the underwriters or their affiliates. The representatives may agree to allocate a number of units to underwriters for sale to their online brokerage account holders. The representatives will allocate units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, units may be sold by the underwriters to securities dealers who resell units to online brokerage account holders.

 

Other than the prospectus in electronic format, the information on any underwriter’s web site and any information contained in any other web site maintained by an underwriter is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter in its capacity as an underwriter and should not be relied upon by investors.

 

We and our general partner have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and the liabilities incurred in connection with the directed unit program referred to above, and to contribute to payments the underwriters may be required to make because of any of those liabilities.

 

VALIDITY OF THE UNITS

 

The validity of the units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the units will be passed upon for the underwriters by Andrews Kurth LLP, Houston, Texas. Attorneys at Vinson & Elkins L.L.P. who have participated in the preparation of this prospectus, the registration statement of which this prospectus is a part and the related transaction documents beneficially own approximately 3,200 common units of Enterprise Products Partners.

 

EXPERTS

 

The consolidated financial statements as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004 of Enterprise Products GP, LLC included in this prospectus and the related financial statement schedule included elsewhere in the registration statement of which this prospectus constitutes a part have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein and elsewhere in the registration statement, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

 

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Index to Financial Statements

The balance sheets of Enterprise GP Holdings L.P. and EPE Holdings, LLC included in this prospectus and included elsewhere in the registration statement of which this prospectus forms a part have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports appearing herein and elsewhere in the registration statement and are included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

 

The (1) consolidated financial statements of GulfTerra Energy Partners, L.P. (“GulfTerra”), (2) the financial statements of Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”) and (3) the combined financial statements of El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. (the “Companies”) included in this prospectus have been included in reliance on the reports (which (i) report on the consolidated financial statements of GulfTerra contains an explanatory paragraph relating to GulfTerra’s agreement to merge with Enterprise Products Partners L.P. as described in Note 2 to the consolidated financial statements, (ii) report on the financial statements of Poseidon contains an explanatory paragraph relating to Poseidon’s restatement of its prior year financial statements as described in Note 1 to the financial statements, and (iii) report on the combined financial statements of the Companies contains an explanatory paragraph relating to the Companies’ significant transactions and relationships with affiliated entities as described in Note 5 to the combined financial statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

 

Information set forth in this prospectus with respect to GulfTerra’s estimated oil and natural gas reserves is derived from the report of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists, and is included in reliance on the authority of said firm as experts in independent petroleum engineering and geology.

 

FORWARD-LOOKING STATEMENTS

 

This prospectus contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. In particular, a significant amount of information included under “Our Cash Distribution Policy and Restrictions on Distributions” is comprised of forward-looking statements. When used in this prospectus or the documents we have incorporated herein or therein by reference, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may,” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may have a direct bearing on our results of operations and financial condition are:

 

    fluctuations in oil, natural gas and NGL prices and production due to weather and other natural and economic forces;

 

    a reduction in demand for Enterprise Products Partners’ products by the petrochemical, refining or heating industries;

 

    the effects of our debt level on our future financial and operating flexibility;

 

    the effects of Enterprise Products Partners’ debt level on its future financial and operating flexibility;

 

    a decline in the volumes of NGLs delivered by Enterprise Products Partners’ facilities;

 

    the failure of Enterprise Products Partners’ credit risk management efforts to adequately protect it against customer non-payment;

 

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    terrorist attacks aimed at Enterprise Products Partners’ facilities;

 

    our failure to successfully integrate assets or companies we may acquire;

 

    Enterprise Products Partners’ failure to successfully integrate its operations with GulfTerra’s or any other assets or companies it acquires; and

 

    Enterprise Products Partners’ failure to realize the anticipated cost savings, synergies and other benefits associated with the GulfTerra merger.

 

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” in this prospectus.

 

WHERE YOU CAN FIND MORE INFORMATION

 

We have filed with the Commission a registration statement on Form S-1 regarding the units offered by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the units offered by this prospectus, you should review the full registration statement, including its exhibits and schedules, filed under the Securities Act of 1933. The registration statement of which this prospectus constitutes a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the Commission at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549. Copies of the materials may also be obtained from the Commission at prescribed rates by writing to the public reference room maintained by the Commission at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the Commission at 1-800-SEC-0330. The Commission maintains a website on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded at no cost from the Commission’s web site. We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

 

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INDEX TO FINANCIAL STATEMENTS

 

Enterprise GP Holdings L.P.

   

Unaudited Pro Forma Condensed Consolidated Financial Statements:

   

Introduction

  F-3

Unaudited Pro Forma Condensed Statement of Consolidated Operations for the Three Months Ended March 31, 2005

  F-5

Unaudited Pro Forma Condensed Statement of Consolidated Operations for the Year Ended December 31, 2004

  F-6

Unaudited Pro Forma Condensed Consolidated Balance Sheet at March 31, 2005

  F-8

Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements

  F-9

Enterprise GP Holdings L.P.

   

Audited Balance Sheet:

   

Report of Independent Registered Public Accounting Firm

  F-21

Balance Sheet at May 31, 2005

  F-22

Notes to Balance Sheet

  F-23

EPE Holdings, LLC

   

Audited Balance Sheet:

   

Report of Independent Registered Public Accounting Firm

  F-24

Balance Sheet at May 31, 2005

  F-25

Note to Balance Sheet

  F-26

Enterprise Products GP, LLC

   

Unaudited Condensed Consolidated Financial Statements:

   

Unaudited Condensed Consolidated Balance Sheet at March 31, 2005

  F-27

Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income for the Three Months Ended March 31, 2005 and 2004

  F-28

Unaudited Condensed Statements of Consolidated Cash Flows for the Three Months Ended March 31, 2005 and 2004

  F-29

Unaudited Condensed Statements of Consolidated Members’ Equity for the Three Months Ended March 31, 2005

  F-30

Notes to Unaudited Condensed Consolidated Financial Statements

  F-31

Enterprise Products GP, LLC

   

Audited Consolidated Financial Statements:

   

Report of Independent Registered Public Accounting Firm

  F-54

Consolidated Balance Sheets at December 31, 2004 and 2003

  F-55

Statements of Consolidated Operations and Comprehensive Income for the Years Ended December 31, 2004, 2003 and 2002

  F-56

Statements of Consolidated Cash Flows for the Years Ended December 31, 2004, 2003 and 2002

  F-57

Statements of Consolidated Members’ Equity for the Years Ended December 31, 2004, 2003 and 2002

  F-58

Notes to Consolidated Financial Statements and Supplemental Schedule

  F-59

GulfTerra Energy Partners, L.P.

   

Audited Consolidated Financial Statements:

   

Report of Independent Registered Public Accounting Firm

  F-124

Consolidated Statements of Income for the Years Ended December 31, 2003, 2002 and 2001

  F-125

Consolidated Balance Sheets at December 31, 2003 and 2002

  F-127

Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001

  F-128

 

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Index to Financial Statements

Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2003, 2002 and 2001

  F-130

Consolidated Statements of Comprehensive Income and Changes in Accumulated Other Comprehensive Income (Loss) for the Years Ended December 31, 2003, 2002 and 2001

  F-131

Notes to Consolidated Financial Statements

  F-132

Poseidon Oil Pipeline Company, L.L.C.

   

Audited Financial Statements:

   

Report of Independent Registered Public Accounting Firm

  F-205

Statements of Income for the Years Ended December 31, 2003, 2002 and 2001

  F-206

Balance Sheets as of December 31, 2003 and 2002

  F-207

Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001

  F-208

Statements of Members’ Capital for the Years Ended December 31, 2003, 2002 and 2001

  F-209

Statements of Comprehensive Income and Changes in Accumulated Other Comprehensive Income for the Years Ended December 31, 2003, 2002 and 2001

  F-210

Notes to Financial Statements

  F-211

GulfTerra Energy Partners, L.P.

   

Unaudited Condensed Consolidated Financial Statements:

   

Unaudited Condensed Consolidated Balance Sheets at September 30, 2004

  F-220

Unaudited Condensed Consolidated Statements of Income for the Six Months Ended June 30, 2004, Three and Nine Months Ended September 30, 2004, and the Three and Nine Months Ended September 30, 2003

  F-221

Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2004, Three and Nine Months Ended September 30, 2004, and the Three and Nine Months Ended September 30, 2003

  F-222

Unaudited Condensed Consolidated Statements of Comprehensive Income and Changes in Accumulated Other Comprehensive Loss for the Six Months Ended June 30, 2004, Three and Nine Months Ended September 30, 2004 and the Three and Nine Months Ended September 30, 2003

  F-223

Notes to Unaudited Condensed Consolidated Financial Statements

  F-224

El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P.

   

Audited Combined Financial Statements:

   

Report of Independent Registered Public Accounting Firm

  F-243

Combined Balance Sheets at December 31, 2003 and 2002

  F-244

Combined Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001

  F-245

Combined Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001

  F-246

Combined Statements of Owners’ Net Investment for the Years Ended December 31, 2003, 2002 and 2001

  F-247

Combined Statements of Comprehensive Income and Changes in Accumulated Other Comprehensive Income (Loss) for the Years Ended December 31, 2003, 2002 and 2001

  F-248

Notes to Combined Financial Statements

  F-249

El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P.

   

Unaudited Combined Financial Statements:

   

Combined Balance Sheets at June 30, 2004 and December 31, 2003

  F-260

Combined Statements of Operations for the Six Months Ended June 30, 2004 and 2003

  F-261

Combined Statements of Cash Flows for the Six Months Ended June 30, 2004 and 2003

  F-262

Combined Statements of Comprehensive Income and Changes in Accumulated Other Comprehensive Income for the Six Months Ended June 30, 2004 and 2003

  F-263

Notes to Combined Financial Statements

  F-264

 

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Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Introduction

 

Unless the context requires otherwise, for purposes of this pro forma presentation, references to “we,” “our,” “us,” “Enterprise GP Holdings” or “the Company” are intended to mean the consolidated business and operations of Enterprise GP Holdings L.P. References to “Enterprise Products Partners” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P., which includes its primary operating subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”). References to “Enterprise Products GP” refer to Enterprise Products GP, LLC, the general partner of Enterprise Products Partners.

 

References to “GulfTerra” are intended to mean the consolidated business and operations of GulfTerra Energy Partners, L.P. References to “El Paso” are intended to mean El Paso Corporation, its subsidiaries and affiliates. References to “EPCO” are intended to mean EPCO, Inc., an affiliate of the Company and our ultimate parent company.

 

These unaudited pro forma condensed consolidated financial statements give effect to significant transactions and events that affect Enterprise GP Holdings, including:

 

    The sale of 12,000,000 common units by Enterprise GP Holdings in this initial public offering and related use of proceeds as described in Note (z) beginning on page F-19.

 

    The completion by Enterprise Products Partners of its merger with GulfTerra and related transactions on September 30, 2004 (the “GulfTerra Merger”). The GulfTerra Merger took place in three steps as described beginning on page F-9. In addition, this pro forma financial information reflects the related sale by Enterprise Products Partners of its 50% equity interest in Starfish Pipeline Company, LLC (“Starfish”) on March 31, 2005.

 

    The issuance by the Operating Partnership of $2 billion of senior unsecured notes on October 4, 2004. Net proceeds from this offering were used to reduce debt outstanding under the Operating Partnership’s $2.25 billion 364-Day Acquisition Credit Facility, which was used to fund certain payment obligations related to the GulfTerra Merger.

 

    The completion on October 5, 2004 of the Operating Partnership’s four cash tender offers for $915 million in principal amount of GulfTerra’s senior and senior subordinated notes using $1.1 billion borrowed under the Operating Partnership’s $2.25 billion 364-Day Acquisition Credit Facility on September 30, 2004.

 

    The use of proceeds from the sale of 17,250,000 common units by Enterprise Products Partners (including subsequent over-allotment amounts) in each of May 2004, August 2004 and February 2005. In addition, this pro forma financial information reflects the receipt of proceeds from the issuance of 410,249 common units by Enterprise Products Partners in connection with its distribution reinvestment plan (“DRIP”) in May 2005.

 

    The issuance by the Operating Partnership in February 2005 of $250 million in principal amount of 5.00% senior notes due March 2015 and $250 million in principal amount of 5.75% senior notes due March 2035 and related use of proceeds.

 

    The issuance by the Operating Partnership in May 2005 of $500 million in principal amount of 4.95% senior notes due June 2010 and related use of proceeds.

 

The unaudited pro forma condensed statements of consolidated operations for the three months ended March 31, 2005 and for the year ended December 31, 2004 assumes the pro forma transactions noted herein occurred on January 1, 2004 (to the extent not already reflected in the historical statements of consolidated operations of each entity). The unaudited pro forma condensed consolidated balance sheet shows the financial

 

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Index to Financial Statements

effects of the pro forma transactions noted herein as if they had occurred on March 31, 2005 (to the extent not already recorded in the historical balance sheet of Enterprise Products GP). GulfTerra’s historical income statement for the year ended December 31, 2004 includes $19.9 million in merger-related costs incurred prior to September 30, 2004.

 

Enterprise GP Holdings was formed in April 2005, and thus it does not have any historical financial statements for 2004. As a result of being under common control with Enterprise Products GP, Enterprise GP Holdings’ unaudited pro forma condensed consolidated financial information reflects the unaudited pro forma condensed consolidated financial information of Enterprise Products GP. Likewise, Enterprise Products Partners’ financial information is consolidated with Enterprise Products GP due to the same common control considerations. The unaudited pro forma condensed consolidated financial statements of Enterprise GP Holdings reflect the elimination of all material intercompany accounts and transactions.

 

Dollar amounts presented in the tabular data within these unaudited pro forma condensed consolidated financial statements and footnotes (except per unit amounts) are stated in thousands of dollars, unless otherwise indicated.

 

The unaudited pro forma condensed consolidated financial statements and related pro forma information are based on assumptions that Enterprise GP Holdings believes are reasonable under the circumstances and are intended for informational purposes only. They are not necessarily indicative of the financial results that would have occurred if the transactions described herein had taken place on the dates indicated, nor are they indicative of the future consolidated results of the combined company.

 

The unaudited pro forma condensed consolidated financial statements of Enterprise GP Holdings should be read in conjunction with, and are qualified in their entirety by reference to, the notes accompanying such unaudited pro forma condensed consolidated financial statements, the historical consolidated financial statements, and the unaudited condensed consolidated statements and related notes of Enterprise Products GP included within this prospectus.

 

The condensed consolidated financial statements of GulfTerra included herein are qualified in their entirety by reference to the historical consolidated financial statements and related notes of GulfTerra for the three and nine months ended September 30, 2004 included within this prospectus.

 

The combined financial statements for the eight months ended August 31, 2004 of El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. (collectively, the “South Texas midstream assets”) included herein were derived from the historical accounts and records of these entities.

 

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Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Three Months Ended March 31, 2005

 

     Enterprise
Products
GP
Historical


    Pro Forma
Adjustments


        Enterprise
GP Holdings
Pro Forma


    Adjustments
Due to this
Offering


        As Adjusted
Enterprise
GP Holdings
Pro Forma


 

REVENUES

   $ 2,555,522                 $ 2,555,522                 $ 2,555,522  

COSTS AND EXPENSES

                                                

Operating costs and expenses

     2,383,644     $  5,558     (o)     2,389,202                   2,389,202  

General and administrative

     15,153       750     (w)     15,903                   15,903  
    


 


     


             


Total costs and expenses

     2,398,797       6,308           2,405,105                   2,405,105  
    


 


     


             


EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES

     8,279       (313 )   (o)     7,966                   7,966  
    


 


     


             


OPERATING INCOME

     165,004       (6,621 )         158,383                   158,383  
    


 


     


             


OTHER INCOME (EXPENSE)

                                                

Interest expense

     (53,413 )     2,515     (l)     (59,704 )   $  4,513   (z )     (55,191 )
               2,384     (m)                            
               (137 )   (n)                            
               (3,070 )   (q)                            
               (216 )   (r)                            
               (7,767 )   (v)                            

Interest expense—related parties

     (5,639 )     5,639     (v)                            

Other, net

     924                   924                   924  
    


 


     


 

       


Total

     (58,128 )     (652 )         (58,780 )     4,513           (54,267 )
    


 


     


 

       


INCOME BEFORE PROVISION FOR INCOME TAXES AND MINORITY INTEREST

     106,876       (7,273 )         99,603       4,513           104,116  

PROVISION FOR INCOME TAXES

     (1,769 )                 (1,769 )                 (1,769 )
    


 


     


 

       


INCOME BEFORE MINORITY INTEREST

     105,107       (7,273 )         97,834       4,513           102,347  

MINORITY INTEREST

     (95,664 )     7,520     (x)     (88,144 )                 (88,144 )
    


 


     


 

       


INCOME FROM CONTINUING OPERATIONS

   $ 9,443     $ 247         $ 9,690     $ 4,513         $ 14,203  
    


 


     


 

       


INCOME ALLOCATION

                                                

Limited partners (99.99%)

                       $ 9,689                 $ 14,202  
                        


             


General partner (0.01%)

                         1                   1  
                        


             


BASIC EARNINGS PER UNIT

                                                

Number of units used in denominator

             74,667     (u)     74,667       12,000   (z )     86,667  
                        


             


Income from continuing operations

                       $ 0.13                 $ 0.16  
                        


             


DILUTED EARNINGS PER UNIT

                                                

Number of units used in denominator

             74,667     (u)     74,667       12,000   (z )     86,667  
                        


             


Income from continuing operations

                       $ 0.13                 $ 0.16  
                        


             


 

 

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

 

F-5


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Year Ended December 31, 2004 (Part 1)

 

   

Enterprise
Products

GP
Historical


    GulfTerra
Historical


    South
Texas
Midstream
Assets
Historical


  Pro Forma
Adjustments


        Enterprise
GP
Holdings
Pro Forma
(to Part 2)


 

REVENUES

  $ 8,321,202     $ 676,722     $ 1,103,178   $ (426,584 )   (g)   $ 9,615,119  
                            (59,399 )   (k)        

COSTS AND EXPENSES

                                         

Operating costs and expenses

    7,904,336       432,258       1,058,330     103,655     (f)     8,971,209  
                            (421,469 )   (g)        
                            (46,502 )   (j)        
                            (59,399 )   (k)        

General and administrative

    47,264                     46,502     (j)     96,766  
                            3,000     (w)        
   


 


 

 


     


Total costs and expenses

    7,951,600       432,258       1,058,330     (374,213 )         9,067,975  
   


 


 

 


     


EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES

    52,787                     (32,024 )   (h)     24,830  
                            7,567     (j)        
                            (3,500 )   (o)        
   


 


 

 


     


OPERATING INCOME

    422,389       244,464       44,848     (139,727 )         571,974  
   


 


 

 


     


OTHER INCOME (EXPENSE)

                                         

Interest expense

    (155,740 )     (82,678 )           5,149     (a)     (266,792 )
                            (78,475 )   (b)        
                            22,488     (b)        
                            (18,029 )   (c)        
                            2,959     (d)        
                            56,262     (e)        
                            18,733     (l)        
                            7,765     (m)        
                            (410 )   (n)        
                            (12,450 )   (q)        
                            (866 )   (r)        
                            (31,500 )   (v)        

Interest expense—related parties

    (5,849 )                   5,849     (v)        

Loss due to early redemptions of debt

            (16,285 )                       (16,285 )

Earnings from unconsolidated affiliates

            7,567             (7,567 )   (j)        

Other, net

    2,130       472             1,200     (i)     3,802  
   


 


       


     


Total

    (159,459 )     (90,924 )           (28,892 )         (279,275 )
   


 


       


     


INCOME BEFORE PROVISION FOR INCOME TAXES AND MINORITY INTEREST

    262,930       153,540       44,848     (168,619 )         292,699  

PROVISION FOR INCOME TAXES

    (3,761 )                               (3,761 )
   


 


 

 


     


INCOME BEFORE MINORITY INTEREST

    259,169       153,540       44,848     (168,619 )         288,938  

MINORITY INTEREST

    (228,716 )     1,825             (45,797 )   (x)     (272,688 )
   


 


 

 


     


INCOME FROM CONTINUING OPERATIONS

  $ 30,453     $ 155,365     $ 44,848   $ (214,416 )       $ 16,250  
   


 


 

 


     


INCOME ALLOCATION

                                         

Limited partners (99.99%)

                                    $ 16,248  
                                     


General partner (0.01%)

                                    $ 2  
                                     


BASIC EARNINGS PER UNIT

                                         

Number of units used in denominator

                          74,667     (u)     74,667  
                                     


Income from continuing operations

                                    $ 0.22  
                                     


DILUTED EARNINGS PER UNIT

                                         

Number of units used in denominator

                          74,667     (u)     74,667  
                                     


Income from continuing operations

                                    $ 0.22  
                                     


 

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

 

F-6


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Year Ended December 31, 2004 (Part 2)

 

     Enterprise
GP Holdings
Pro Forma
(from Part 1)


    Adjustments
Due to this
Offering


        As Adjusted
Enterprise
GP Holdings
Pro Forma


 

REVENUES

   $ 9,615,119                 $ 9,615,119  

COSTS AND EXPENSES

                            

Operating costs and expenses

     8,971,209                   8,971,209  

General and administrative

     96,766                   96,766  
    


             


Total

     9,067,975                   9,067,975  
    


             


EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES

     24,830                   24,830  
    


             


OPERATING INCOME

     571,974                   571,974  
    


             


OTHER INCOME (EXPENSE)

                            

Interest expense

     (266,792 )   $ 18,301   (z )     (248,491 )

Loss due to early redemptions of debt

     (16,285 )                 (16,285 )

Other, net

     3,802                   3,802  
    


 

       


Total

     (279,275 )     18,301           (260,974 )
    


 

       


INCOME BEFORE PROVISION FOR INCOME TAXES AND MINORITY INTEREST

     292,699       18,301           311,000  

PROVISION FOR INCOME TAXES

     (3,761 )                 (3,761 )
    


 

       


INCOME BEFORE MINORITY INTEREST

     288,938       18,301           307,239  

MINORITY INTEREST

     (272,688 )                 (272,688 )
    


 

       


INCOME FROM CONTINUING OPERATIONS

   $ 16,250     $ 18,301         $ 34,551  
    


 

       


INCOME ALLOCATION:

                            

Limited partners (99.99%)

   $ 16,248                 $ 34,548  
    


             


General partner (0.01%)

   $ 2                 $ 3  
    


             


BASIC EARNINGS PER UNIT:

                            

Number of units used in denominator

     74,667       12,000   (z )     86,667  
    


             


Income from continuing operations

   $ 0.22                 $ 0.40  
    


             


DILUTED EARNINGS PER UNIT:

                            

Number of units used in denominator

     74,667       12,000   (z )     86,667  
    


             


Income from continuing operations

   $ 0.22                 $ 0.40  
    


             


 

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

 

F-7


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

March 31, 2005

 

     Enterprise
Products GP
Historical


   Pro Forma
Adjustments


          Enterprise
GP Holdings
Pro Forma


   Adjustments
Due to this
Offering


          As Adjusted
Enterprise
GP Holdings
Pro Forma


ASSETS

                                                

Current assets

                                                

Cash and cash equivalents

   $ 68,132    $ 10,400     (p )   $ 274,202    $ 324,000     (z )   $ 274,202
              495,670     (q )            (18,980 )   (z )      
              (300,000 )   (q )            (305,020 )   (z )      
              525,000     (v )                           
              (525,000 )   (v )                           

Accounts and notes receivable, net

     946,968                    946,968                    946,968

Inventories

     309,552                    309,552                    309,552

Other current assets

     89,016      700     (q )     89,716                    89,716
    

  


       

  


       

Total current assets

     1,413,668      206,770             1,620,438      —               1,620,438
Property, plant and equipment, net Investments in and advances to unconsolidated affiliates     
 
8,059,247
557,979
     405,151     (s )    
 
8,059,247
557,979
                  
 
8,059,247
557,979
              78,124     (t )                           
              (483,275 )   (y )                           

Intangible assets, net

     960,137                    960,137                    960,137

Goodwill

     456,694                    456,694                    456,694

Other assets

     80,040      2,800     (q )     82,840                    82,840
    

  


       

  


       

Total assets

   $ 11,527,765    $ 209,570           $ 11,737,335    $ —             $ 11,737,335
    

  


       

  


       

LIABILITIES AND EQUITY

                                                

Current liabilities

                                                

Current maturities of debt

   $ 32,630    $ (3,630 )   (v )   $ 29,000                  $ 29,000

Accounts payable and accrued expenses

     1,326,613                    1,326,613                    1,326,613

Other current liabilities

     112,926                    112,926                    112,926
    

  


       

                

Total current liabilities

     1,472,169      (3,630 )           1,468,539                    1,468,539

Long-term debt

     4,490,082      500,000     (q )     4,852,473    $ (305,020)     (z )     4,547,453
              (830 )   (q )                           
              (300,000 )   (q )                           
              159,591     (s )                           
              525,000     (v )                           
              (159,591 )   (v )                           
              (361,779 )   (v )                           

Other long-term liabilities

     78,418                    78,418                    78,418

Minority interest

     5,315,188      10,192     (p )     5,014,221                    5,014,221
              (311,159 )   (y )                           

Commitments and contingencies

                                                

Combined equity

                                                

Members’ equity

     171,908      208     (p )                           
              (172,116 )   (y )                           

Partners’ equity

                                                

Limited partners

            245,559     (s )     323,676      305,020     (z )     628,696
              78,117     (t )                           

General partner

            1     (s )     8                    8
              7     (t )                           
    

  


       

  


       

Total equity

     171,908      151,776             323,684      305,020             628,704
    

  


       

  


       

Total liabilities and equity

   $ 11,527,765    $ 209,570           $ 11,737,335    $ —             $ 11,737,335
    

  


       

  


       

 

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

 

F-8


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS

 

These unaudited pro forma condensed consolidated financial statements and underlying pro forma adjustments are based upon information currently available and certain estimates and assumptions made by the management of Enterprise GP Holdings; therefore, actual results could materially differ from the pro forma information. However, Enterprise GP Holdings believes the assumptions provide a reasonable basis for presenting the significant effects of the transactions noted herein. Enterprise GP Holdings believes the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the pro forma information.

 

Completion of the GulfTerra Merger Transactions

 

On September 30, 2004, Enterprise Products Partners and GulfTerra completed the merger of GulfTerra with a wholly-owned subsidiary of Enterprise Products Partners, with GulfTerra being the surviving entity thereof. Additionally, Enterprise Products Partners completed certain other transactions related to the merger, including receipt of Enterprise Products GP’s contribution of a 50% membership interest in GulfTerra’s general partner (“GulfTerra GP”), which was acquired by Enterprise Products GP from El Paso, and the purchase of certain midstream energy assets located in South Texas from El Paso. The aggregate value of the total consideration Enterprise Products Partners paid or issued to complete the GulfTerra Merger was approximately $4 billion. These transactions were accounted for using purchase accounting.

 

The historical consolidated balance sheet of Enterprise Products GP at March 31, 2005 already reflects the GulfTerra merger. Since the GulfTerra Merger closed during the day of September 30, 2004, the Statement of Consolidated Operations of Enterprise Products GP for the year ended December 31, 2004 includes three months of results of operations from the GulfTerra assets. The effective closing date of the Operating Partnership’s purchase of the South Texas midstream assets was September 1, 2004. As a result, the Statement of Consolidated Operations of Enterprise Products GP for the year ended December 31, 2004 includes four months of results of operations from the South Texas midstream assets. The historical Statement of Consolidated Operations of Enterprise Products GP for the three months ended March 31, 2005 includes the results of operations from the GulfTerra assets and South Texas midstream assets.

 

As a result of the GulfTerra Merger, GulfTerra and GulfTerra GP became wholly owned subsidiaries of Enterprise Products Partners on September 30, 2004. On October 1, 2004, Enterprise Products Partners contributed its ownership interests in GulfTerra and GulfTerra GP to the Operating Partnership, which resulted in GulfTerra and GulfTerra GP becoming wholly owned subsidiaries of the Operating Partnership.

 

GulfTerra manages a balanced, diversified portfolio of interests and assets relating to the midstream energy sector, which involves gathering, transporting, separating, processing, fractionating and storing natural gas, oil and NGLs. GulfTerra’s interests and assets included (i) offshore oil and natural gas pipelines, platforms, processing facilities and other energy infrastructure in the Gulf of Mexico, primarily offshore Louisiana and Texas; (ii) onshore natural gas pipelines and processing facilities in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas; (iii) onshore NGL pipelines and fractionation facilities in Texas; and (iv) onshore natural gas and NGL storage facilities in Louisiana, Mississippi and Texas.

 

The South Texas midstream assets consist of nine natural gas processing plants with a combined capacity of 1.9 Bcf/d, a 294-mile natural gas gathering system, a natural gas treating facility with a capacity of 150 MMcf/d and a small NGL pipeline.

 

The GulfTerra Merger transactions

 

The GulfTerra Merger occurred in several interrelated steps as described below.

 

   

Step One. On December 15, 2003, Enterprise Products Partners purchased a 50% membership interest in GulfTerra GP from El Paso for $425 million in cash. GulfTerra GP owned a 1% general partner interest

 

F-9


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

 

in GulfTerra. Prior to completion of the GulfTerra Merger, Enterprise Products Partners accounted for its investment in GulfTerra GP using the equity method of accounting. The $425 million in funds required to complete Step One were borrowed by the Operating Partnership under an Interim Term Loan and its pre-merger revolving credit facilities. These borrowings were fully repaid with the net proceeds from equity offerings completed during 2004 by Enterprise Products Partners.

 

    Step Two. On September 30, 2004, the GulfTerra Merger was consummated and GulfTerra and GulfTerra GP became wholly owned subsidiaries of Enterprise Products Partners. Step Two of the GulfTerra Merger included the following:

 

    Immediately prior to closing the GulfTerra Merger, Enterprise Products GP acquired El Paso’s remaining 50% membership interest in GulfTerra GP for $370 million in cash paid to El Paso and the issuance of a 9.9% membership interest in Enterprise Products GP to El Paso. Subsequently, Enterprise Products GP contributed this 50% membership interest in GulfTerra GP to Enterprise Products Partners without the receipt of additional general partner interest, common units or other consideration. Enterprise Products GP borrowed the foregoing $370 million from one of its former members, Dan Duncan LLC, which obtained the funds through a loan from EPCO.

 

    Immediately prior to closing the GulfTerra Merger, Enterprise Products Partners paid $500 million in cash to El Paso for 10,937,500 Series C units of GulfTerra and 2,876,620 common units of GulfTerra. The remaining 57,762,369 GulfTerra common units (7,433,425 of which were owned by El Paso) were converted into 104,549,823 Enterprise Products Partners common units (13,454,498 of which were held by El Paso prior to January 2005) at the time of the consummation of the GulfTerra Merger.

 

    Step Three. Immediately after Step Two was completed, Enterprise Products Partners acquired certain South Texas midstream assets from El Paso for $155.3 million in cash. Pursuant to written agreements, the Operating Partnership’s purchase of the South Texas midstream assets was effective September 1, 2004.

 

In connection with the closing of the GulfTerra Merger on September 30, 2004, the Operating Partnership borrowed an aggregate of $2.6 billion under its 364-Day Acquisition Credit Facility and Multi-Year Revolving Credit Facility (collectively referred to as the “Merger Credit Facilities”) in order to fund its cash payment obligations under Step Two and Step Three of the GulfTerra Merger, including the tender offers for GulfTerra’s outstanding senior and senior subordinated notes.

 

F-10


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The total consideration paid or granted for the GulfTerra Merger Transactions is summarized below:

 

Step One transaction:

        

Cash payment by Enterprise Products Partners to El Paso for initial 50% membership interest in GulfTerra GP (a non-voting interest) made in December 2003

   $ 425,000  
    


Total Step One consideration

     425,000  
    


Step Two transactions:

        

Cash payment by Enterprise Products Partners to El Paso for 10,937,500 GulfTerra Series C units and 2,876,620 GulfTerra common units

     500,000  

Fair value of equity interests granted to acquire remaining 50% membership interest in GulfTerra GP (voting interest) and cash payment of $370 million by Enterprise Products GP to El Paso (1)

     461,347  

Fair value of Enterprise Products Partners common units issued in exchange for remaining GulfTerra common units

     2,445,420  

Fair value of other Enterprise Products Partners equity interests granted for unit awards and Series F2 convertible units

     4,004  

Fair value of receivable from El Paso for transition support payments (2)

     (40,313 )

Transaction fees and other direct costs incurred by Enterprise Product Partners as a result of the GulfTerra Merger (3)

     30,485  
    


Total Step Two consideration

     3,400,943  
    


Total Step One and Step Two consideration

     3,825,943  
    


Step Three transaction:

        

Purchase of South Texas midstream assets from El Paso

     155,277  
    


Total consideration for Steps One through Three

   $ 3,981,220  
    



(1) This fair value is based on 50% of an implied $922.7 million total value of GulfTerra GP, which assumes that the $370 million cash payment made by Enterprise Products GP to El Paso represented consideration for a 40.1% interest in GulfTerra GP. The 40.1% interest was derived by deducting the 9.9% membership interest in Enterprise Products GP granted to El Paso in this transaction from the 50% membership interest in GulfTerra GP that Enterprise Products GP received. The fair value of $461.3 million assigned to this voting membership interest in GulfTerra GP compares favorably to the $425 million paid to El Paso by Enterprise Products Partners to purchase its initial 50% non-voting membership interest in GulfTerra GP in December 2003. The contribution of this 50% membership interest to Enterprise Products Partners is allocated for financial reporting purposes to Enterprise Products Partners’ limited partners and general partner based on the respective ownership percentages and the related allocation of profits and losses of 98% and 2%, respectively, both of which are consistent with Enterprise Products Partners’ partnership agreement.
(2) Reflects the present value of a contract-based receivable from El Paso received as part of the negotiated net consideration reached in Step One of the GulfTerra Merger. The agreements between Enterprise Products Partners and El Paso provide that for a period of three years following the closing of the GulfTerra Merger, El Paso will make transition support payments to Enterprise Products Partners in annual amounts of $18 million, $15 million and $12 million for the first, second and third years of such period, respectively, payable in twelve equal monthly installments for each such year. The $45 million receivable from El Paso has been discounted to fair value and recorded as a reduction in the purchase consideration for GulfTerra. This contract-based receivable was recorded at its fair value of $40.3 million and classified within other assets on Enterprise Products GP’s condensed Consolidated Balance Sheet at December 31, 2004.

 

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Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

(3) As a result of the GulfTerra Merger, Enterprise Products Partner incurred expenses of approximately $30.5 million for various transaction fees and other direct costs. These direct costs include fees for legal, accounting, printing, financial advisory and other services rendered by third-parties to Enterprise Products Partners over the course of the GulfTerra Merger transactions. This amount also includes $3.4 million of involuntary severance costs.

 

Allocation of purchase price of GulfTerra Merger transactions

 

The GulfTerra Merger transactions were recorded using the purchase method of accounting. Purchase accounting requires us to allocate the cost of a business combination to the assets acquired and liabilities assumed based on their estimated fair values. Enterprise Products Partners has engaged an independent third-party business valuation expert to assess the fair value of GulfTerra’s and the South Texas midstream asset’s tangible and intangible assets. This information will assist management in the development of a definitive allocation of the overall purchase price of the GulfTerra Merger Transactions.

 

The preliminary fair values shown in the following table are estimates based on information available to management at March 31, 2005. The valuation estimates shown below could change due to this very recent transaction and the refinement of our estimates.

 

     Merger-Related Transactions

       
     Step Two of
GulfTerra
Merger


   

Step Three
Purchase of

South Texas

Midstream
Assets


    Total

 

Purchase price allocation:

                        

Assets acquired in business combination:

                        

Current assets, including cash of $40,453

   $ 207,211     $ 7,614     $ 214,825  

Property, plant and equipment, net

     4,601,390       112,830       4,714,220  

Investments in and advances to unconsolidated affiliates

     202,672               202,672  

Intangible assets

     705,459       37,802       743,261  

Other assets

     26,881               26,881  
    


 


 


Total assets acquired

     5,743,613       158,246       5,901,859  
    


 


 


Liabilities assumed in business combination:

                        

Current liabilities

     (228,477 )     (2,969 )     (231,446 )

Long-term debt, including current maturities

     (2,015,583 )             (2,015,583 )

Other long-term liabilities

     (47,880 )             (47,880 )
    


 


 


Total liabilities assumed

     (2,291,940 )     (2,969 )     (2,294,909 )
    


 


 


Total assets acquired less liabilities assumed

     3,451,673       155,277       3,606,950  

Total consideration given

     3,825,943       155,277       3,981,220  
    


 


 


Remaining Goodwill

   $ 374,270     $ —       $ 374,270  
    


 


 


 

As a result of the preliminary purchase price allocation for Steps Two and Three of the GulfTerra Merger transactions, Enterprise Products Partners recorded $743.3 million of amortizable intangible assets, primarily those related to customer relationships and contracts. The remaining preliminary amount represents goodwill of $374.3 million associated with our view of the future results from GulfTerra’s operations, based on the strategic location of GulfTerra’s assets as well as their industry relationships.

 

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Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Pro Forma Adjustments

 

The pro forma adjustments made to the consolidated or combined historical financial statements of Enterprise Products GP, GulfTerra and the South Texas midstream assets are described as follows:

 

(a) Reflects the sale of 17,250,000 common units by Enterprise Products Partners (including subsequent over-allotment amounts) in each of May and August 2004 and the related use of proceeds. In May 2004, 17,250,000 common units were sold to the public generating net proceeds of $353.1 million, which were used to repay the Operating Partnership’s $225 million Interim Term Loan and to temporarily reduce borrowings outstanding under the Operating Partnership’s then existing revolving credit facilities by approximately $128.1 million. In August 2004, 17,250,000 common units were sold to the public generating net proceeds of $341.2 million, of which $210 million was used to temporarily reduce borrowings under the Operating Partnership’s then existing revolving credit facilities and the remainder to fund Enterprise Products Partners’ payment obligations to El Paso in connection with Step Two of the GulfTerra Merger transactions.

 

As a result of the use of $563.1 million in proceeds from these offerings to reduce debt outstanding, pro forma interest expense decreased $5.1 million for the year ended December 31, 2004. In calculating the pro forma adjustment to interest expense for the year ended December 31, 2004, we used an average historical variable interest rate of 1.8%, which was determined by reference to the debt obligations that were either completely repaid or temporarily reduced using proceeds from such offerings. If the variable interest rates used to determine the pro forma adjustments to interest expense were 1/8% higher, the pro forma reduction in interest expense would have been $5.5 million for the year ended December 31, 2004.

 

Since the receipt of proceeds from these offerings and the related increases in minority interest and members’ equity are already reflected in Enterprise Products GP’s condensed historical consolidated balance sheet at March 31, 2005, no pro forma adjustments to the balance sheet are necessary.

 

(b) On September 30, 2004, the Operating Partnership borrowed approximately $2.6 billion under its Merger Credit Facilities to (i) fund cash payment obligations to El Paso under Step Two and Step Three of the GulfTerra Merger transactions, (ii) escrow $1.1 billion in cash to finance its tender offers for GulfTerra’s senior and senior subordinated notes and (iii) repay $962 million outstanding under GulfTerra’s revolving credit facility and secured term loans on the merger closing date.

 

The pro forma adjustment to interest expense resulting from these borrowings is $78.5 million for the year ended December 31, 2004. In calculating the pro forma adjustment to interest expense, we used an estimated variable interest rate of 4.1%, which approximates the interest rate we are currently being charged on amounts borrowed under our Multi-Year Revolving Credit Facility. If this estimated interest rate were 1/8% higher, the pro forma adjustment to interest expense would be $80.9 million for the year ended December 31, 2004. The pro forma adjustment to interest expense also reflects the removal of historical interest expense amounts recorded by GulfTerra related to its revolving credit facility and secured term loans of $22.5 million for the year ended December 31, 2004. Enterprise Products GP’s condensed historical consolidated balance sheet at March 31, 2005 already reflects these borrowings; therefore, no pro forma adjustment is required.

 

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Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

(c) On October 4, 2004, the Operating Partnership issued $2 billion of senior unsecured notes in a private offering. The net proceeds from this offering were used to reduce debt outstanding under the Merger Credit Facilities. The fixed-interest rate, principal amount issued and net proceeds (before offering expenses) of each series of senior notes in this offering were as follows:

 

Senior Note Issued


   Fixed
Interest
Rate


    Principal
Amount


   Bond
Discount


   Proceeds to Us,
Before
Expenses


Senior Notes E, due October 2007

   4.000 %   $ 500,000    $ 2,140    $ 497,860

Senior Notes F, due October 2009

   4.625 %     500,000      4,405      495,595

Senior Notes G, due October 2014

   5.600 %     650,000      4,784      645,216

Senior Notes H, due October 2034

   6.650 %     350,000      4,203      345,797
          

  

  

Totals

         $ 2,000,000    $ 15,532    $ 1,984,468
          

  

  

 

After giving effect to the application of proceeds to reduce principal amounts outstanding under the Operating Partnership’s variable-rate Merger Credit Facilities, the pro forma adjustment to interest expense resulting from the issuance of these senior notes is $18 million for the year ended December 31, 2004. If the variable-rates used to calculate the reduction in interest expense associated with the repayment of amounts outstanding under the Merger Credit Facilities were 1/8% higher, the pro forma adjustment to interest expense would have been $16.2 million for the year ended December 31, 2004. Enterprise Products GP’s condensed historical consolidated balance sheet at March 31, 2005 already reflects this transaction; therefore, no pro forma adjustment is required.

 

(d) During 2004, the Operating Partnership entered into eight forward-starting interest rate swap transactions in anticipation of financing activities associated with closing the GulfTerra Merger transactions. The Operating Partnership’s purpose in entering into these transactions was to effectively hedge the underlying U.S. treasury rate related to our expected issuance of $2 billion of fixed-rate debt. On October 4, 2004, the Operating Partnership issued $2 billion of senior unsecured notes in a private offering (see Note (c)). Each of the forward starting swaps was designated as a cash flow hedge in accordance with applicable accounting guidance.

 

In April 2004, the Operating Partnership elected to terminate the initial four forward-starting swaps in order to manage and maximize the value of the swaps and to reduce future debt service costs. As a result, it received $104.5 million in cash from the counterparties. In September 2004, the remaining four swaps were settled resulting in an $85.1 million payment to the counterparties. The net gain of $19.4 million from these eight swaps was recorded in accumulated other comprehensive income and will be amortized to earnings over the life of the associated debt as a reduction in interest expense and accumulated other comprehensive income. The pro forma amortization of this gain reduced interest expense by $3 million for the year ended December 31, 2004. No pro forma adjustment to the condensed consolidated balance sheet of Enterprise Products GP at March 31, 2005 is required.

 

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Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

(e) On October 4, 2004, all of the cash tender offers made by the Operating Partnership for any and all of GulfTerra’s outstanding senior and senior subordinated notes expired. As of the expiration time, the Operating Partnership had received tenders of such notes aggregating $915 million, or 99.3% of the notes outstanding. On October 5, 2004, the Operating Partnership purchased the notes for a total price of approximately $1.1 billion using amounts borrowed under the Merger Credit Facilities. The following table shows the four GulfTerra senior debt obligations affected, including the principal amount of each series of notes tendered, as well as the payment made by the Operating Partnership to complete the tender offers.

 

    

Principal

Amount
Tendered


   Cash payments made by Enterprise

Description


      Accrued
Interest


  

Tender

Price (1)


  

Total

Paid


8.50% Senior Subordinated Notes due 2010
(Represented 98.2% of principal amount outstanding)

   $ 212,057    $ 6,209    $ 246,366    $ 252,575

10.625% Senior Subordinated Notes due 2012
(Represented 99.9% of principal amount outstanding)

     133,916      4,901      167,612      172,513

8.50% Senior Subordinated Notes due 2011
(Represented 99.5% of principal amount outstanding)

     319,823      9,364      359,379      368,743

6.25% Senior Notes due 2010
(Represented 99.7% of principal amount outstanding)

     249,250      5,366      274,073      279,439
    

  

  

  

Totals

   $ 915,046    $ 25,840    $ 1,047,430    $ 1,073,270
    

  

  

  


(1) Tender price includes consent payment of $30 per $1,000 principal amount tendered.

 

The pro forma adjustments to interest expense reflect the removal of historical interest expense amounts recorded by GulfTerra associated with such senior note obligations. These adjustments decreased pro forma fixed-rate interest expense by $56.3 million for the year ended December 31, 2004. Enterprise Products GP’s condensed historical balance sheet at March 31, 2005 already reflects these transactions; therefore, no pro forma adjustment is required.

 

(f) Reflects the pro forma depreciation and amortization adjustment for GulfTerra’s and the South Texas midstream assets’ property, plant and equipment and intangible assets based on the preliminary purchase price allocation for the GulfTerra Merger transactions. For purposes of calculating pro forma depreciation expense, we applied the straight-line method using estimated remaining useful lives ranging from 10 years to 33 years (depending on the type of asset) to Enterprise Products Partners’ new basis in such assets of approximately $4.7 billion.

 

In addition, Enterprise Products Partners recorded $743.3 million of amortizable intangible assets, which are primarily comprised of the fair value of certain customer relationships and storage contracts. For purposes of calculating pro forma amortization expense attributable to the customer relationship intangible assets, we based such expense primarily on the patterns in which the economic benefits of each intangible asset are expected to be consumed by referencing the forecasted production rates of the underlying resource bases (i.e., the oil and gas reserves associated with the customer relationship intangible assets) from which the customers produce. For purposes of calculating pro forma amortization expense attributable to the storage contract intangible assets, we applied the straight-line method to the remainder of the respective contract terms, which we estimate could range from 2 to 18 years.

 

F-15


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Overall, the pro forma depreciation and amortization expense adjustment was $103.7 million for the year ended December 31, 2004, after taking into account the historical expense amounts recorded by GulfTerra and the South Texas midstream assets.

 

(g) In accordance with the purchase and sale agreement between Enterprise Products Partners and El Paso for the South Texas midstream assets, El Paso retained a number of natural gas liquids marketing contracts. Enterprise Products GP’s pro forma condensed statement of consolidated operations for the year ended December 31, 2004 includes adjustments to remove $426.6 million of revenues and $421.5 million of operating costs and expenses associated with these retained contracts.

 

(h) After Step Two of the GulfTerra Merger was completed on September 30, 2004, GulfTerra GP became a wholly owned subsidiary of Enterprise Products Partners. This pro forma adjustment reflects the replacement of equity earnings from GulfTerra GP that Enterprise Products Partners recorded under Step One of the GulfTerra Merger, with consolidated earnings from GulfTerra, as if Step Two had occurred on January 1, 2004. This adjustment required the removal of $32 million of equity earnings from GulfTerra GP that Enterprise Products Partners recorded during the first nine months of 2004. Enterprise Products Partners acquired its initial 50% membership interest in GulfTerra GP on December 15, 2003 under Step One of the GulfTerra Merger.

 

(i) In connection with the GulfTerra Merger transactions, Enterprise Products Partners recorded the present value of a contract-based receivable from El Paso totaling $40.3 million, which was part of the negotiated net consideration reached in Step Two of the GulfTerra Merger. Our pro forma condensed statement of consolidated operations reflects $1.2 million of imputed interest income that would have been recognized from this agreement during 2004.

 

(j) Reflects pro forma classification adjustments necessary to conform GulfTerra’s and the South Texas midstream assets’ historical condensed statements of consolidated operations to Enterprise Products Partners’ method of presentation. The reclassifications were as follows:

 

    GulfTerra’s and the South Texas midstream assets’ general and administrative costs were reclassified to a separate line item within costs and expenses to conform to Enterprise Products Partners’ method of presentation. GulfTerra’s and the South Texas midstream assets’ general and administrative costs were $46.5 million for the year ended December 31, 2004.

 

    GulfTerra’s operating income increased as a result of reclassifying its equity earnings from unconsolidated affiliates to a separate component of operating income to conform with Enterprise GP Holdings’ presentation of such earnings. As a result of this reclassification, GulfTerra’s operating income increased by $7.6 million for the year ended December 31, 2004. Enterprise Products Partners’ equity investments with industry partners are a vital component of its business strategy. Such investments are a means by which Enterprise Products Partners conducts its operations to align its interests with those of its customers, which may be a supplier of raw materials or a consumer of finished products. This method of operation also enables Enterprise Products Partners to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what Enterprise Products Partners could accomplish on a stand-alone basis. Many of these equity investments perform supporting or complementary roles to Enterprise Products Partners’ other business operations. GulfTerra has a similar relationship with its equity investments.

 

(k) Reflects the pro forma elimination of significant revenues and expenses between Enterprise Products Partners, GulfTerra and the South Texas midstream assets as appropriate in consolidation. Upon completion of

 

F-16


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

the GulfTerra Merger transactions, GulfTerra and the South Texas midstream assets became wholly owned subsidiaries of Enterprise Products Partners.

 

(l) Reflects the sale of 17,250,000 common units by Enterprise Products Partners in February 2005 generating net proceeds of approximately $456.9 million, which were used to fully repay the Operating Partnership’s 364-Day Acquisition Credit Facility, to temporarily reduce debt outstanding under the Operating Partnership’s Multi-Year Revolving Credit Facility and the remainder for general partnership purposes. Net proceeds from this offering includes a $9.1 million contribution from Enterprise Products GP to maintain its 2% general partner interest in Enterprise Products Partners.

 

As a result of our pro forma application of proceeds from this offering to reduce debt outstanding, pro forma interest expense decreased by $2.5 million for the three months ended March 31, 2005 and $18.7 million for the year ended December 31, 2004. If the variable rates used to calculate the reduction in interest expense associated with the repayment of amounts outstanding under the Merger Credit Facilities were 1/8% higher, the pro forma adjustment to interest expense would have been $2.6 million for the three months ended March 31, 2005 and $19.3 million for the year ended December 31, 2004.

 

(m) Reflects the Operating Partnership’s combined issuance of $500 million of senior notes in February 2005 comprised of $250 million in principal amount of 5.00% senior notes due March 2015 (“Senior Notes I”) and $250 million in principal amount of 5.75% senior notes due March 2035 (“Senior Notes J”). The Operating Partnership used the $490.6 million in net proceeds from the issuance of these fixed-rate senior notes (after $9.4 million in bond discounts and debt issuance costs) to retire its $350 million in principal amount 8.25% Senior Notes A (due March 2005) and to temporarily reduce indebtedness outstanding under its Multi-Year Revolving Credit Facility.

 

After giving effect to the issuance of Senior Notes I and J in March 2005 and the related application of net proceeds, pro forma interest expense would decrease by $2.4 million for the three months ended March 31, 2005 and by $7.8 million for the year ended December 31, 2004. If the variable interest rate underlying the Multi-Year Revolving Credit Facility were 1/8% higher, the pro forma decrease in interest expense would have been $2.4 million for the three months ended March 31, 2005 and $7.9 million for the year ended December 31, 2004.

 

(n) The net proceeds from issuance of Senior Notes I and J described in Note (m) reflect the payment of $9.4 million in bond discounts and debt issuance costs. For pro forma purposes, we have amortized these costs over the term of the senior notes they are associated with using the straight-line method. As a result, pro forma interest expense increased by $0.1 million for the three months ended March 31, 2005 and $0.4 million for the year ended December 31, 2004.

 

(o) Reflects the sale by Enterprise Products Partners of its 50% equity investment in Starfish, which owns the Stingray natural gas pipeline and related gathering pipelines and dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana. In connection with obtaining regulatory approval for the GulfTerra Merger, Enterprise Products Partners was required by the FTC to sell its ownership interest in Starfish by March 31, 2005. On March 31, 2005, Enterprise Products Partners sold this asset to a third-party for $42.1 million in cash and realized a gain on the sale of $5.5 million.

 

Enterprise Products Partners recognized equity earnings from Starfish of $0.3 million for the three months ended March 31, 2005 and $3.5 million for the year ended December 31, 2004. The pro forma adjustments

 

F-17


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

reflect the removal of these equity earnings since, for pro forma purposes, we have assumed that the sale of Starfish occurred immediately prior to January 1, 2004. Likewise, we have removed the $5.5 million gain on the sale of Starfish from Enterprise Product GP’s results of operations for the three months ended March 31, 2005. Enterprise Products GP’s condensed historical consolidated balance sheet at March 31, 2005 already reflects the sale of Starfish; therefore, no pro forma adjustments are required.

 

(p) Reflects Enterprise Products Partners’ issuance of 410,249 common units in May 2005 in connection with its DRIP and related programs, which generated net proceeds of approximately $10.4 million including $0.2 million from Enterprise Products GP to maintain its 2% general partner interest in Enterprise Products Partners. Enterprise Products Partners used the net proceeds from this offering for general partnership purposes; therefore, these proceeds are reflected as an increase in cash on hand in the pro forma condensed consolidated balance sheet of Enterprise Products GP at March 31, 2005.

 

(q) Reflects the Operating Partnership’s issuance in June 2005 of $500 million in principal amount of 4.95% senior notes due June 2010 (“Senior Notes K”). The Operating Partnership used the $495.7 million in net proceeds from the issuance of these fixed-rate senior notes to temporarily reduce debt outstanding under its Multi-Year Revolving Credit Facility and the reminder for general partnership purposes, including capital expenditures and business combinations.

 

After giving effect to the issuance of Senior Notes K in June 2005 and the related application of net proceeds, pro forma interest expense would increase by $3.1 million for the three months ended March 31, 2005 and $12.5 million for the year ended December 31, 2004. If the variable interest rate underlying the Multi-Year Revolving Credit Facility were  1 / 8 % higher, the pro forma increase in interest expense would have been $3.0 million for the three months ended March 31, 2005 and $12.1 million for the year ended December 31, 2004.

 

(r) The net proceeds from the issuance of Senior Notes K described in Note (q) reflect the payment of $4.3 million in bond discounts and debt issuance costs. For pro forma purposes, we have amortized these costs over the five year term of the senior notes using the straight-line method. As a result, pro forma interest expense increased by $0.2 million for the three months ended March 31, 2005 and $0.9 million for the year ended December 31, 2004.

 

(s) Reflects the contribution of 13,454,498 Enterprise Products Partners common units and a 9.9% member interest in Enterprise Products GP to Enterprise GP Holdings from DFI GP Holdings L.P. (“DGPH”) at its formation in April 2005. The pro forma adjustment reflects the contribution of these assets at their historical carrying basis since the contributions to Enterprise GP Holdings are from a related party.

 

As consideration for such transfers, Enterprise GP Holdings assumed $159.6 million of debt from DGPH and issued DGPH a 100% partnership interest in Enterprise GP Holdings valued at $245.6 million. Subsequently, the partnership interest issued to DGPH was distributed 99.99% to other affiliates of EPCO (Duncan Family Interests, Inc. and Dan Duncan LLC) and 0.01% to EPE Holdings, LLC, which is the general partner of Enterprise GP Holdings. The pro forma adjustments reflect the consideration given by Enterprise GP Holdings to DGPH and the subsequent establishment of limited and general partner book capital accounts.

 

(t) Reflects the contribution of the remaining 90.1% member interests in Enterprise Products GP to Enterprise GP Holdings by Duncan Family Interests, Inc. and Dan Duncan LLC and the related issuance of additional limited partner interests in Enterprise GP Holdings to these companies as consideration. Duncan Family Interests, Inc. owned 85.595% and Dan Duncan LLC owned 4.505% of Enterprise Products GP prior to

 

F-18


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

this contribution. As a result of these transactions, Enterprise Products GP will be a wholly owned subsidiary of Enterprise GP Holdings. In addition, this pro forma adjustment reflects a nominal cash contribution by EPE Holdings, LLC to Enterprise GP Holdings to maintain its 0.01% general partner interest in Enterprise GP Holdings.

 

(u) As a result of the limited partner contributions to Enterprise GP Holdings described in Notes (s) and (t), Duncan Family Interests, Inc and Dan Duncan LLC will receive 74,667,332 common units of Enterprise GP Holdings.

 

(v) Reflects the borrowing of $525 million by Enterprise GP Holdings under a new credit facility and the repayment of the $159.6 million of debt assumed from DGPH described in Note (s) and $365.4 million owed by Enterprise Products GP to Dan Duncan LLC. Enterprise Products GP borrowed these funds from Dan Duncan, LLC in connection with its acquisition of a 50% interest in GulfTerra GP under Step Two of the GulfTerra Merger. Dan Duncan LLC obtained these funds through a loan from EPCO, which will be repaid by Dan Duncan LLC as a result of receiving the repayment from Enterprise GP Holdings.

 

After giving effect to this refinancing, pro forma interest expense for the three months ended March 31, 2005 increased a net $2.1 million, which consisted of $7.8 million of interest expense associated with Enterprise GP Holdings’ new $525 million credit facility less $5.6 million of historical related party interest expense attributable to the Dan Duncan LLC note that was repaid. For the year ended December 31, 2004 pro forma interest expense increased a net $25.7 million, which consisted of $31.5 million of interest expense associated with Enterprise GP Holdings’ new $525 million credit facility less $5.8 million of historical related party interest expense attributable to the Dan Duncan LLC note that was repaid. In calculating the pro forma adjustment to interest expense, we used an estimated variable interest rate of 6.0%. If the variable interest rate underlying the pro forma adjustment were 1/8% higher, the pro forma net increase in interest expense would have been $2.3 million for the three months ended March 31, 2005 and $26.3 million for the year ended December 31, 2004.

 

(w) Reflects the estimated general and administrative costs of Enterprise GP Holdings, which includes director fees, professional services and charges from EPCO related to the Administrative Services Agreement. For additional information regarding the Administrative Services Agreement with EPCO, please read “Certain Relationships and Related Party Transactions—Administrative Services Agreement.”

 

(x) Reflects pro forma adjustments to minority interest (as shown on the condensed consolidated balance sheet) and minority interest expense (as shown on the condensed statements of consolidated operations) resulting from various pro forma adjustments made herein related to the GulfTerra Merger transactions, equity and debt security offerings by Enterprise Products Partners and its Operating Partnership, and the contribution of 13,454,498 Enterprise Products Partners common units to Enterprise GP Holdings by DGPH. Minority interest represents third-party and related party ownership interests in the net assets of certain subsidiaries of Enterprise GP Holdings. The primary group of minority interest holders reflected in the pro forma condensed consolidated balance sheet of Enterprise GP Holdings consists of the third-party and related party owners of the common units of Enterprise Products Partners.

 

(y) Reflects the pro forma elimination of investment and equity accounts between Enterprise GP Holdings and Enterprise Products GP as appropriate in consolidation.

 

(z) Reflects the sale of 12,000,000 common units by Enterprise GP Holdings in this offering at an estimated offering price of $27.00 per common unit. Total net proceeds from the sale of these 12,000,000 common units is

 

F-19


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

approximately $305 million after deducting applicable underwriting discounts, commissions, structuring fees and other offering expenses of $19 million. For pro forma purposes, the total net proceeds from this initial public offering will be used to reduce debt outstanding under Enterprise GP Holdings’ $525 million credit facility, which will leave $196.9 million of indebtedness outstanding. The $196.9 million of remaining debt outstanding under this facility has an initial maturity date of February 2006; however, we expect to refinance this amount with long-term debt prior to this maturity date. This pro forma adjustment does not include the receipt of any proceeds upon the underwriters’ exercise of the over-allotment option.

 

As a result of our pro forma application of total net proceeds from this offering to reduce debt outstanding, pro forma interest expense would decrease by $4.5 million for the three months ended March 31, 2005 and $18.3 million for the year ended December 31, 2004. If the variable rates used to calculate the reduction in interest expense were 1/8% higher, the pro forma adjustment to interest expense would have been $4.6 million for the three months ended March 31, 2005 and $18.7 million for the year ended December 31, 2004.

 

F-20


Table of Contents
Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To EPE Holdings, LLC as general partner of

Enterprise GP Holdings L.P.

 

We have audited the accompanying balance sheet of Enterprise GP Holdings L.P. (the “Company”) as of May 31, 2005. The balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on the balance sheet based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

 

In our opinion, the balance sheet presents fairly, in all material respects, the financial position of the Company as of May 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

 

/s/ DELOITTE & TOUCHE LLP

 

Houston, Texas

June 15, 2005

 

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Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

BALANCE SHEET

AT MAY 31, 2005

 

ASSETS     

Cash

   $ 1,000

Deferred offering costs

     559,781
    

Total assets

   $ 560,781
    

LIABILITIES AND PARTNERS’ EQUITY     

Accounts payable—related parties

     559,781

Partners’ equity

     1,000
    

Total liabilities and partners’ equity

   $ 560,781
    

 

 

 

 

 

See Notes to Balance Sheet

 

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Index to Financial Statements

ENTERPRISE GP HOLDINGS L.P.

 

NOTES TO BALANCE SHEET

 

Nature of Operations

 

Enterprise GP Holdings L.P. is a Delaware limited partnership that was formed on April 19, 2005 to become the sole member of Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners L.P., a publicly traded partnership. Enterprise Products Partners is a North American energy company providing a wide range of processing, storage and transportation or midstream services to producers and consumers of natural gas, natural gas liquids, and crude oil, and an industry leader in the development of pipeline and other midstream infrastructure in the continental United States and deepwater Gulf of Mexico.

 

Our assets will consist of the following partnership interests in Enterprise Products Partners to be contributed to us by EPCO, Inc.:

 

    our 100% ownership of Enterprise Products GP, which owns a 2% general partner interest in Enterprise Products Partners that entitles us to receive 2% of the cash distributed by Enterprise Products Partners;

 

    the incentive distribution rights in Enterprise Products Partners associated with the general partner interest, which entitle us to receive increasing percentages of the cash distributed by Enterprise Products Partners as Enterprise Products Partners’ per unit distribution increases; and

 

    13,454,498 common units of Enterprise Products Partners, representing an approximate 3.4% limited partner interest in Enterprise Products Partners.

 

We will also assume $159.6 million in debt as consideration for the assets contributed to us from EPCO, Inc.

 

Direct offering costs representing specific legal, accounting, and other third party services incurred to date in connection with the anticipated initial public offering of the Company will be deferred and charged against the gross proceeds of the offering. Offering costs paid by related parties prior the offering will be reimbursed from the proceeds of the offering. At this time there are no other obligations for organizational costs intended to be reimbursed to related parties.

 

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Table of Contents
Index to Financial Statements

EPE HOLDINGS, LLC

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors of Dan Duncan LLC and Stockholder of

    EPE Holdings, LLC

    Houston, Texas

 

We have audited the accompanying balance sheet of EPE Holdings, LLC (the “Company”) as of May 31, 2005. The balance sheet is the responsibility of the Company’s management. Our responsibility is to express an opinion on the balance sheet based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion . An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.

 

In our opinion, the balance sheet presents fairly, in all material respects, the financial position of the Company as of May 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

 

/s/ DELOITTE & TOUCHE LLP

 

Houston, Texas

June 15, 2005

 

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Table of Contents
Index to Financial Statements

EPE HOLDINGS, LLC

 

BALANCE SHEET

AT MAY 31, 2005

 

ASSETS       

Cash

   $ 1,000
    

MEMBERS’ EQUITY       

Members’ Equity

   $ 1,000
    

 

 

 

 

See Note to Balance Sheet

 

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Index to Financial Statements

EPE HOLDINGS, LLC

 

NOTE TO BALANCE SHEET

 

NATURE OF OPERATIONS

 

EPE Holdings, LLC is a Delaware limited liability company that was formed on April 19, 2005, to become the 0.01% general partner of Enterprise GP Holdings L.P., a limited partnership that was formed to own Enterprise Products GP, LLC, the general partner of Enterprise Products Partners L.P., and 13,454,498 common units of Enterprise Products Partners L.P. Enterprise GP Holdings L.P. is a wholly owned subsidiary of Dan Duncan LLC. Our general partner interest is fixed without any requirement for capital contributions in connection with additional unit issuances by Enterprise GP Holdings L.P.

 

*    *    *    *

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

 

     March 31,
2005


   December 31,
2004


ASSETS              

Current assets

             

Cash and cash equivalents

   $ 57,774    $ 25,006

Restricted cash

     10,358      26,157

Accounts and notes receivable—trade, net of allowance for doubtful accounts of $23,624 at March 31, 2005 and $24,310 at December 31, 2004

     946,826      1,058,375

Accounts receivable—related parties

     142      25,151

Inventories

     309,552      189,019

Assets held for sale

            36,562

Prepaid and other current assets

     89,016      80,893
    

  

Total current assets

     1,413,668      1,441,163

Property, plant and equipment, net

     8,059,247      7,831,467

Investments in and advances to unconsolidated affiliates

     557,979      519,164

Intangible assets, net of accumulated amortization of $96,794 at March 31, 2005 and $74,183 at December 31, 2004

     960,137      980,601

Goodwill

     456,694      459,198

Deferred tax asset

     8,915      6,467

Long-term receivables

     15,144      14,931

Other assets

     55,981      62,910
    

  

Total assets

   $ 11,527,765    $ 11,315,901
    

  

LIABILITIES AND MEMBERS’ EQUITY              

Current liabilities

             

Current maturities of debt

   $ 32,630    $ 18,450

Accounts payable—trade

     56,038      203,144

Accounts payable—related parties

     17,479      41,293

Accrued gas payables

     1,138,257      1,021,294

Accrued expenses

     45,244      130,051

Accrued interest

     69,595      73,151

Other current liabilities

     112,926      104,979
    

  

Total current liabilities

     1,472,169      1,592,362

Long-term debt

     4,490,082      4,629,219

Other long-term liabilities

     78,418      63,739

Minority interest

     5,315,188      4,865,698

Commitments and contingencies

             

Members’ equity

     171,908      164,883
    

  

Total liabilities and members’ equity

   $ 11,527,765    $ 11,315,901
    

  

 

See Notes to Unaudited Condensed Consolidated Financial Statements

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS

AND COMPREHENSIVE INCOME

(Dollars in thousands)

 

     For the Three Months Ended
March 31,


 
     2005

    2004

 

REVENUES

                

Third parties

   $ 2,497,329     $ 1,549,587  

Related parties

     58,193       155,303  
    


 


Total

     2,555,522       1,704,890  
    


 


COST AND EXPENSES

                

Operating costs and expenses

                

Third parties

     2,318,529       1,405,983  

Related parties

     65,115       215,525  
    


 


Total operating costs and expenses

     2,383,644       1,621,508  
    


 


General and administrative costs

                

Third parties

     5,902       2,604  

Related parties

     9,251       6,894  
    


 


Total general and administrative costs

     15,153       9,498  
    


 


Total costs and expenses

     2,398,797       1,631,006  
    


 


EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES

     8,279       14,867  
    


 


OPERATING INCOME

     165,004       88,751  
    


 


OTHER INCOME (EXPENSE)

                

Interest expense

     (53,413 )     (32,618 )

Interest expense—related parties

     (5,639 )        

Other, net

     924       165  
    


 


Other expense

     (58,128 )     (32,453 )

INCOME BEFORE PROVISION FOR INCOME TAXES, MINORITY INTEREST AND CHANGES IN ACCOUNTING PRINCIPLES

     106,876       56,298  

Provision for income taxes

     (1,769 )     (1,625 )
    


 


INCOME BEFORE MINORITY INTEREST AND CHANGES IN ACCOUNTING PRINCIPLES

     105,107       54,673  

Minority interest

     (95,664 )     (43,608 )
    


 


INCOME BEFORE CHANGES IN ACCOUNTING PRINCIPLES

     9,443       11,065  

Cumulative effect of changes in accounting principles (see Note 1)

             216  
    


 


NET INCOME

     9,443       11,281  

Cash flow financing hedges

             16,973  

Reclassification (amortization) of cash flow financing hedges

     (995 )     (102 )

Change in fair value of commodity hedges

     (1,434 )        
    


 


COMPREHENSIVE INCOME

   $ 7,014     $ 28,152  
    


 


 

See Notes to Unaudited Condensed Consolidated Financial Statements

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in thousands)

 

     For the Three Months
Ended March 31,


 
     2005

    2004

 

OPERATING ACTIVITIES

                

Net income

   $ 9,443     $ 11,281  

Adjustments to reconcile net income to cash flows provided by operating activities:

                

Depreciation and amortization in operating costs and expenses

     99,965       30,520  

Depreciation in general and administrative costs

     1,922       65  

Amortization in interest expense

     (477 )     798  

Equity in income of unconsolidated affiliates

     (8,279 )     (14,867 )

Distributions received from unconsolidated affiliates

     21,838       16,932  

Cumulative effect of changes in accounting principles

             (216 )

Operating lease expense paid by EPCO

     528       2,274  

Minority interest

     95,664       43,608  

Loss (gain) on sale of assets

     (5,436 )     98  

Deferred income tax expense

     1,802       1,687  

Changes in fair market value of financial instruments

     102       3  

Decrease in restricted cash used for operating activities

     15,799       5,825  

Net effect of changes in operating accounts (see Note 12)

     (58,831 )     (68,599 )
    


 


Cash provided by operating activities

     174,040       29,409  
    


 


INVESTING ACTIVITIES

                

Capital expenditures

     (175,230 )     (15,216 )

Contributions in aid of construction costs

     8,942       213  

Proceeds from sale of assets

     42,158       10  

Cash used for business combinations, net of cash received

     (150,478 )        

Acquisition of intangible asset

     (1,750 )        

Investments in and advances to unconsolidated affiliates

     (88,634 )     (818 )
    


 


Cash used in investing activities

     (364,992 )     (15,811 )
    


 


FINANCING ACTIVITIES

                

Borrowings under debt agreements

     1,382,175       202,000  

Repayments of debt

     (1,502,002 )     (137,000 )

Debt issuance costs

     (4,425 )     (954 )

Distributions paid to partners

             (7,000 )

Distributions paid to minority interests

     (149,377 )     (84,061 )

Contributions from minority interests

     497,349       22,954  

Treasury units reissued

             5,109  
    


 


Cash provided by financing activities

     223,720       1,048  
    


 


NET CHANGE IN CASH AND CASH EQUIVALENTS

     32,768       14,646  

CASH AND CASH EQUIVALENTS, JANUARY 1

     25,006       30,466  
    


 


CASH AND CASH EQUIVALENTS, MARCH 31

   $ 57,774     $ 45,112  
    


 


 

See Notes to Unaudited Condensed Consolidated Financial Statements

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

UNAUDITED CONDENSED STATEMENTS OF CONSOLIDATED MEMBERS’ EQUITY

(Dollars in thousands)

 

     DFI

   DFI GP

   DDC

   El Paso

    Accumulated
Other
Comprehensive
Income


    Total

 

Balance, December 31, 2004

   $ 46,104      —      $ 3,380    $ 90,845     $ 24,554     $ 164,883  

Net income

     8,083    $ 1,027      425      (92 )             9,443  

Operating leases paid by EPCO

     9      1      1                      11  

Change in fair value of commodity hedges

                                  (1,434 )     (1,434 )

Interest rate hedging financial instruments recorded as cash flow hedges:

                                             

Amortization of gain as component of interest expense

                                  (995 )     (995 )

Sale of El Paso’s 9.9% membership interest to DFI GP

            90,753             (90,753 )                
    

  

  

  


 


 


Balance, March 31, 2005

   $ 54,196    $ 91,781    $ 3,806    $ —       $ 22,125     $ 171,908  
    

  

  

  


 


 


 

 

 

See Notes to Unaudited Condensed Consolidated Financial Statements

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

1. GENERAL

 

ENTERPRISE PRODUCTS GP, LLC (“EPGP”) is a Delaware limited liability company formed in May 1998 that is the general partner of Enterprise Products Partners L.P. EPGP’s primary business purpose is to manage the affairs and operations of Enterprise Products Partners, L.P. and its subsidiaries (collectively referred to as “EPD”). EPD is a publicly traded Delaware limited partnership listed on the New York Stock Exchange (“NYSE”) under symbol “EPD.” EPD conducts substantially all of its business through its wholly owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”). EPD and the Operating Partnership were formed to acquire, own and operate the natural gas liquids (“NGL”) business of EPCO, Inc. (“EPCO”).

 

Unless the context requires otherwise, references to “we”, “us”, “our”, “EPGP” or the “Company” within these notes shall mean EPGP and its consolidated subsidiaries, which include EPD and its subsidiaries. References to “Shell” shall mean Shell Oil Company, its subsidiaries and affiliates. References to “El Paso” shall mean El Paso Corporation and its affiliates.

 

At March 31, 2005, Duncan Family Interests, Inc. (“DFI”) owned 85.6%, Dan Duncan, LLC (“DDC”) owned 4.5% and DFI GP Holdings LP (“DFI GP”) owned 9.9% of the membership interests of EPGP. DFI, DDC and DFI GP are collectively referred to as the “Members.” EPCO is the ultimate parent of DFI and an affiliate of DDC and DFI GP. In January 2005, DFI GP purchased El Paso’s 9.9% membership interest in us. See Note 10 for additional information regarding this event.

 

In the opinion of the EPGP, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation. Although we believe the disclosures are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the rules and regulations of the SEC. These unaudited financial statements should be read in conjunction with EPGP’s audited financial statements for the year ended December 31, 2004 included in this registration statement. In addition, this financial information should be read in conjunction with EPD’s Form 10-K for the year ended December 31, 2004 and EPD’s Form 10-Q for the three months ended March 31, 2005 (Commission File No. 1-14323). Certain abbreviated entity names, acronyms and other capitalized and industry terms used within these footnotes are defined in the glossary of EPD’s Form 10-Q for the three ended March 31, 2005.

 

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars, unless otherwise indicated.

 

The results of operations for the three months ended March 31, 2005 are not necessarily indicative of results expected for the full year.

 

We have not included earnings per share as we do not have outstanding shares, rather our membership interests as based on ownership percentages.

 

The cumulative effect of changes in accounting principles represents the combined impact of changing (i) the method our BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method and (ii) the method we used to account for our investment in VESCO.

 

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

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

We own a 2% general partner interest in EPD, which conducts substantially all of our business. We have no independent operations and no material assets outside those of EPD. The number of reconciling items between our consolidated financial statements and those of EPD are few. The primary differences between our consolidated balance sheet and that of EPD are minority interest in our net assets by the limited partners of EPD and the elimination of our investment in EPD with our underlying partner’s capital account in EPD. The difference in consolidated net income is primarily an increase in minority interest expense resulting from the allocation of a portion of our consolidated earnings to the limited partners of EPD.

 

As a result of DFI acquiring Shell’s 30% membership interest in EPGP on September 12, 2003, the financial statements of EPD were consolidated with those of EPGP beginning in September 2003. This accounting consolidation is required because Shell’s minority interest rights in EPGP (which gave them significant participating rights) were terminated as a result of the purchase. This fact, along with DFI’s indirect control of EPD through its common unit holdings, gives EPGP the ability to exercise control over EPD. All significant intercompany accounts and transactions have been eliminated in consolidation.

 

2. RECENTLY ISSUED ACCOUNTING STANDARDS

 

SFAS No. 123(R), “Share-Based Payment.” This accounting guidance, which is applicable for public companies the first fiscal year beginning on or after June 15, 2005, replaces SFAS No. 123, “ Accounting for Stock-Based Compensation ” and supersedes APB No. 25, “ Accounting for Stock Issued to Employees .” This Statement eliminates the ability to account for share-based compensation transactions using APB No. 25, and generally requires instead that such transactions be accounted for using a fair-value-based method. We are continuing to evaluate the provisions of SFAS No. 123(R) and will adopt the standard on January 1, 2006. Upon the required effective date, we will apply this statement using a modified version of prospective application as described in the standard.

 

On March 29, 2005, the SEC issued Staff Accounting Bulletin (“SAB”) 107 to provide public companies additional guidance in applying the provisions of SFAS No. 123(R). Among other things, SAB 107 describes the SEC staff’s expectations in determining the assumptions that underlie the fair value estimates and discusses the interaction of SFAS No. 123(R) with certain existing SEC guidance. The guidance is also beneficial to users of financial statements in analyzing the information provided under SFAS No. 123(R). We will apply the provisions of SAB 107 upon the adoption of SFAS No. 123(R).

 

FIN 46(R)-5, “Implicit Variable Interests Under FASB Interpretation No. 46(R), Consolidation of Variable Interest Entities.” On March 3, 2005, the FASB issued this guidance to address whether a reporting enterprise has an implicit variable interest in a variable interest entity or potential variable interest entity when specific conditions exist. FIN 46(R)-5 covers issues that commonly arise in leasing arrangements among related parties, as well as other types of arrangements involving both related and unrelated parties. Implicit variable interests are implied financial interests in an entity’s net assets exclusive of variable interests. An implicit variable interest acts the same as in an explicit variable interest except it involves the absorbing and (or) receiving of variability indirectly from the entity (rather than directly). The identification of an implicit variable interest is a matter of judgment that depends on the relevant facts and circumstances. This guidance is effective for our fiscal quarter ending June 30, 2005. We are continuing to evaluate the provisions of FIN 46(R)-5, which may affect certain non-material leases of office space from a related party.

 

FIN 47, “Accounting for Conditional Asset Retirement Obligations.” Under SFAS No. 143, “Accounting for Asset Retirement Obligations,” a company must record a liability for its legal obligations resulting from the eventual retirement of its tangible long-lived assets, whether that obligation results from the acquisition, construction, or development of the asset. However, many companies have not recorded a liability, concluding

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

that either (1) the conditional nature of the obligation does not create a liability until the retirement activity occurs or (2) the timing and/or the method of settling the obligation is unknown. FIN 47 concludes otherwise. If required legally, an obligation associated with the asset’s retirement is inevitable even though uncertainties exist about the timing and/or method of settling the obligation. According to FIN 47, these uncertainties affect the fair value of the liability, rather than prevent the need to record one at all. Additionally, the ability of a company to postpone indefinitely the settlement of the obligation, or to sell the asset prior to its retirement, does not relieve a company of its present duty to settle the obligation. We are currently studying the effects of FIN 47 on our accounting policy for asset retirement obligations. We will adopt FIN 47 in December 2005.

 

3. BUSINESS COMBINATIONS

 

Indian Springs acquisition in January 2005. In January 2005, we paid El Paso $74.5 million for their membership interests in Teco Gas Gathering, LLC and Teco Gas Processing, LLC. As a result of this acquisition, we indirectly own an 80% equity interest in the 89-mile Indian Springs Gathering System and a 75% equity interest in the Indian Springs natural gas processing facility, both of which are located in East Texas. The Indian Springs processing facility has capacity to process up to 120 MMcf/d of natural gas and there is an idle 20 MMcf/d production train available for restart to support increases in natural gas volumes. The natural gas processed at the Indian Springs processing facility is sourced from the Indian Springs Gathering System, as well as our nearby Big Thicket Gathering System.

 

Acquisition of additional interests in Dixie in January and February 2005. We purchased an approximate 20% interest in Dixie from an affiliate of ConocoPhillips in January 2005 for $31 million and an approximate 26% interest in Dixie from an affiliate of ChevronTexaco in February 2005 for $40 million. As a result of these acquisitions, our ownership interest in Dixie increased to approximately 66% and Dixie became a consolidated subsidiary of ours in February 2005. Dixie owns and operates the 1,301-mile Dixie Pipeline, which transports propane from supply areas in Texas, Louisiana and Mississippi to markets throughout the southeastern United States. The Dixie Pipeline is regulated by the FERC and transports an average of approximately 100 MBPD of propane.

 

GulfTerra Merger purchase price and purchase price allocation adjustments. During the first quarter of 2005, we made purchase price adjustments related to the GulfTerra Merger, and we revised our preliminary purchase price allocation related to the GulfTerra Merger. The purchase price adjustments of $6.5 million were primarily attributable to merger-related financial advisory services and involuntary severance costs, both of which were attributable to the GulfTerra Merger.

 

The GulfTerra Merger was completed on September 30, 2004, when GulfTerra merged with a wholly owned subsidiary of Enterprise Products Partners. The aggregate value of total consideration Enterprise Products Partners paid or issued to complete the GulfTerra Merger was approximately $4 billion. Our purchase price allocations related to the GulfTerra Merger remain preliminary and could change due to the refinement of our estimates.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Allocation of purchase price for 2005 business combinations and other purchase accounting adjustments

 

The acquisitions and post-closing purchase price adjustments described previously were accounted for under the purchase method of accounting and, accordingly, the cost of each has been allocated to the assets acquired and liabilities assumed based on their estimated fair values as follows:

 

     Indian
Springs


   Dixie

    GulfTerra

    Other

   Total

 

Purchase price allocation:

                                      

Assets acquired in business combination:

                                      

Current assets

   $ 355    $ 6,038     $ 8,864            $ 15,257  

Property, plant and equipment, net

     74,500      125,734             $ 1,121      201,355  

Investments in and advances to unconsolidated affiliates

            (36,279 )                    (36,279 )

Other assets

            276                      276  
    

  


 


 

  


Total assets acquired

     74,855      95,769       8,864       1,121      180,609  
    

  


 


 

  


Liabilities assumed in business combination:

                                      

Current liabilities

            (6,620 )     89              (6,531 )

Long-term debt

            (13,972 )                    (13,972 )

Other long-term liabilities

            (2,552 )                    (2,552 )

Minority interest

            (4,576 )                    (4,576 )
    

  


 


 

  


Total liabilities assumed

     —        (27,720 )     89       —        (27,631 )
    

  


 


 

  


Total assets acquired less liabilities assumed

     74,855      68,049       8,953       1,121      152,978  

Total consideration given

     74,855      68,049       6,453       1,121      150,478  
    

  


 


 

  


Goodwill

   $ —      $ —       $ (2,500 )   $ —      $ (2,500 )
    

  


 


 

  


 

The purchase price allocations shown in the preceding table for the recent Indian Springs and Dixie business combinations are preliminary. Enterprise has engaged an independent third-party business valuation expert to assess the fair values of the tangible and intangible assets of these entities. This information will assist management in the development of definitive allocations of the overall purchase prices for these transactions.

 

4. INVENTORIES

 

Our inventories consisted of the following at the dates indicated:

 

     March 31,
2005


   December 31,
2004


Working inventory

   $ 309,025    $ 171,485

Forward-sales inventory

     527      17,534
    

  

Inventory

   $ 309,552    $ 189,019
    

  

 

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

 

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Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Costs and expenses, as shown on our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income, includes cost of sales related to inventories. For the three months ended March 31, 2005 and 2004, such consolidated cost of sales amounts were $2.1 billion and $1.5 billion, respectively.

 

Due to fluctuating prices in the NGL, natural gas and petrochemical industry, we occasionally recognize lower of cost or market adjustments when the carrying values of our inventories exceed their net realizable value. These non-cash adjustments are charged to cost of sales within operating costs and expenses in the period they are recognized. For the three months ended March 31, 2005 and 2004, we recognized $9.6 million and $4.2 million, respectively, of such adjustments.

 

5. PROPERTY, PLANT AND EQUIPMENT

 

Our property, plant and equipment and accumulated depreciation were as follows at the dates indicated:

 

     Estimated
Useful Life
in Years


    March 31,
2005


   December 31,
2004


Plants and pipelines(1)

   5-35 (5)   $ 7,933,372    $ 7,691,197

Underground and other storage facilities(2)

   5-35 (6)     527,619      531,394

Platforms and facilities(3)

   23-31       162,645      162,645

Transportation equipment(4)

   3-10       7,422      7,240

Land

           30,293      29,142

Construction in progress

           296,603      230,375
          

  

Total

           8,957,954      8,651,993

Less accumulated depreciation

           898,707      820,526
          

  

Property, plant and equipment, net

         $ 8,059,247    $ 7,831,467
          

  


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

 

Depreciation expense for the three months ended March 31, 2005 and 2004 was $78.9 million and $26.8 million, respectively. Capitalized interest on our construction projects for the three months ended March 31, 2005 and 2004 was $4.4 million and $0.3 million, respectively.

 

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Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

6. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

 

We own interests in a number of related businesses that are accounted for using the equity method. Our investments in and advances to our unconsolidated affiliates are grouped according to the business segment to which they relate. For a general discussion of our business segments, see Note 14. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated.

 

     Ownership
Percentage at
March 31,
2005


    Investments in and advances to
Unconsolidated Affiliates at


       March 31,
2005


   December 31,
2004


Offshore Pipelines & Services:

                   

Poseidon

   36 %   $ 64,617    $ 63,944

Cameron Highway(1)

   50 %     126,581      114,354

Deepwater Gateway

   50 %     119,098      56,527

Neptune

   25.67 %     71,109      72,052

Nemo

   33.92 %     12,932      12,586

Onshore Natural Gas Pipelines & Services:

                   

Evangeline

   49.5 %     2,939      2,810

Coyote

   50 %     2,218      2,441

NGL Pipelines & Services:

                   

Dixie(2)

                  32,514

VESCO

   13.1 %     37,762      38,437

Belle Rose

   41.7 %     10,059      10,172

Promix

   50 %     63,378      65,748

BRF

   32.3 %     26,784      27,012

Petrochemical Services:

                   

BRPC

   30 %     15,574      15,617

La Porte

   50 %     4,928      4,950
          

  

Total

         $ 557,979    $ 519,164
          

  


(1) Cameron Highway began deliveries of Gulf of Mexico crude oil production to major refining markets along the Texas Gulf Coast during the first quarter of 2005.
(2) We acquired an additional 20% ownership interest in Dixie in January 2005 and an additional 26.1% ownership interest in February 2005. As a result of these acquisitions, Dixie became a consolidated subsidiary.

 

In connection with obtaining regulatory approval for the GulfTerra Merger, we were required by the FTC to sell our ownership interest in Starfish by March 31, 2005. The $36.6 million carrying value of this investment was classified as “Assets held for sale” on our balance sheet at December 31, 2004. On March 31, 2005, we sold this asset to a third-party for $42.1 million in cash and realized a gain on the sale of $5.5 million.

 

On occasion, the price we pay to acquire an investment exceeds the carrying value of the underlying historical net assets (i.e., the underlying equity account balances on the books of the investee) that we purchase. These excess cost amounts are a component of our investments in and advances to unconsolidated affiliates. At March 31, 2005, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway and Nemo included excess cost. At March 31, 2005, excess cost amounts included in our investments in and advances to unconsolidated affiliates totaled $49.7 million, which was attributed to tangible assets. Amortization of our excess cost amounts attributed to tangible assets was $0.7 million and $0.5 million during the three months ended March 31, 2005 and 2004, respectively.

 

F-36


Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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

 

     For the Three Months
Ended March 31,


     2005

   2004

Offshore Pipelines & Services

   $ 2,975    $ 983

Onshore Natural Gas Pipelines & Services

     580      24

NGL Pipelines & Services

     4,448      2,911

Petrochemical Services

     276      395

Other(1)

            10,554
    

  

Total

   $ 8,279    $ 14,867
    

  


(1) This category represents equity income from GulfTerra GP. In connection with the GulfTerra Merger, GulfTerra GP became a wholly owned consolidated subsidiary on September 30, 2004. We had previously accounted for our 50% ownership interest in GulfTerra GP as an equity method investment from December 15, 2003 through September 29, 2004.

 

Summarized financial information of unconsolidated affiliates

 

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

 

     Summarized Income Statement Information for the
Three Months Ended


     March 31, 2005

   March 31, 2004

     Revenues

   Operating
Income


   Net
Income


   Revenues

   Operating
Income


   Net
Income


Offshore Pipelines & Services

   $ 366,836    $ 14,464    $ 8,523    $ 14,641    $ 5,806    $ 4,644

Onshore Natural Gas Pipelines & Services

     53,354      2,147      1,072      50,920      3,071      1,098

NGL Pipelines & Services

     70,031      13,508      13,774      60,184      9,995      9,994

Petrochemical Services

     4,095      1,129      1,141      4,641      1,544      1,540

 

7. INTANGIBLE ASSETS AND GOODWILL

 

Intangible assets

 

The following table summarizes our intangible assets (which primarily consist of contracts and customer relationships) at the dates indicated by segment:

 

          At March 31, 2005

   At December 31, 2004

    

Gross

Value


   Accum.
Amort.


    Carrying
Value


   Accum.
Amort.


    Carrying
Value


Offshore Pipelines & Services

   $ 207,012    $ (13,687 )   $ 193,325    $ (6,965 )   $ 200,047

Onshore Natural Gas Pipelines & Services

     434,150      (16,798 )     417,352      (8,344 )     425,806

NGL Pipelines & Services

     359,237      (60,612 )     298,625      (53,666 )     303,424

Petrochemical Services

     56,532      (5,697 )     50,835      (5,208 )     51,324
    

  


 

  


 

Total

   $ 1,056,931    $ (96,794 )   $ 960,137    $ (74,183 )   $ 980,601
    

  


 

  


 

 

F-37


Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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

 

     For the Three Months
Ended March 31,


     2005

   2004

Offshore Pipelines & Services

   $ 6,722       

Onshore Natural Gas Pipelines & Services

     8,454       

NGL Pipelines & Services

     6,946    $ 3,327

Petrochemical Services

     489      496
    

  

Total

   $ 22,611    $ 3,823
    

  

 

For the remainder of 2005, amortization expense associated with these intangible assets is currently estimated at $63.9 million.

 

Goodwill

 

The following table summarizes our goodwill amounts by segment at the dates indicated. Of the $456.7 million of goodwill we have recorded at March 31, 2005, $374.3 million relates to goodwill we recorded in connection with the GulfTerra Merger.

 

    

March 31,

2005


  

December 31,

2004


Offshore Pipelines & Services

   $ 61,934    $ 62,348

Onshore Natural Gas Pipelines & Services

     288,467      290,397

NGL Pipelines & Services

     32,603      32,763

Petrochemical Services

     73,690      73,690
    

  

Totals

   $ 456,694    $ 459,198
    

  

 

8. RELATED PARTY TRANSACTIONS

 

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

 

    

For the Three Months

Ended March 31,


     2005

   2004

Revenues from consolidated operations

             

EPCO

   $ 284    $ 2,143

Shell

            104,100

Unconsolidated affiliates

     57,909      49,060
    

  

Total

   $ 58,193    $ 155,303
    

  

Operating costs and expenses

             

EPCO

   $ 57,044    $ 39,113

TEPPCO

     1,503       

Shell

            166,830

Unconsolidated affiliates

     6,568      9,582
    

  

Total

   $ 65,115    $ 215,525
    

  

General and administrative expenses

             

EPCO

   $ 9,251    $ 6,894
    

  

 

F-38


Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Historically, Shell was considered a related party because it owned more than 10% of EPD’s limited partner interests and, prior to September 2003, it owned a 30% ownership interest in us. As a result of Shell selling a portion of its limited partner interests in EPD to a third party in December 2004 and March 2005, Shell now owns less than 10% of EPD’s common units. In September 2003, Shell sold its 30% interest in us to an affiliate of EPCO. As a result of Shell’s reduced equity interest in EPD and its lack of control of Enterprise, Shell ceased to be considered a related party beginning in the first quarter of 2005.

 

Relationship with EPCO. We have an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is one of our directors and Chairman. In addition, our executive and other officers are employees of EPCO, including Robert G. Phillips who is Chief Executive Officer and one of our directors.

 

At December 31, 2004, EPCO and DDC, together, owned 90.1% of our membership interests. In January 2005, an affiliate of EPCO acquired El Paso’s 9.9% membership interest in us. As a result of this transaction, EPCO and its affiliates own 100% of our membership interests.

 

We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees. We also have entered into an agreement with EPCO to provide trucking services for us for the transportation of NGLs and other products. In addition, we also buy from and sell to EPCO’s Canadian affiliate certain NGL products.

 

We and EPD are both separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from EPCO and its other affiliates. Historically, EPCO depended on cash distributions it received as an equity owner in EPD to fund most of its other operations and to meet its debt obligations. For the three months ended March 31, 2005 and 2004, EPCO affiliates received $46.8 million and $43.4 million in distributions from EPD, respectively.

 

Relationship with TEPPCO. On February 24, 2005, an affiliate of EPCO acquired Texas Eastern Products Pipeline Company, LLC (“TEPPCO GP”), the general partner of TEPPCO Partners, L.P. (“TEPPCO”), and 2,500,000 common units of TEPPCO from Duke Energy Field Services, LLC (“Duke Energy”) for approximately $1.2 billion in cash. TEPPCO GP owns a 2% general partner interest in TEPPCO and is the managing partner of TEPPCO and its subsidiaries. Subsequently, EPCO reconstituted the board of directors of TEPPCO GP and Dr. Ralph Cunningham (a former independent director) was named Chairman of TEPPCO GP. Due to EPCO’s actions to reconstitute the board of directors of TEPPCO GP and TEPPCO GP’s ability to direct the management of TEPPCO, TEPPCO GP and TEPPCO became related parties to EPCO, EPGP and EPD during the first quarter of 2005.

 

On March 11, 2005, the Bureau of Competition of the FTC delivered written notice to EPCO’s legal advisor that it was conducting a non-public investigation to determine whether EPCO’s acquisition of TEPPCO GP may tend substantially to lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with EPCO’s purchase of TEPPCO GP. EPCO and its affiliates, including us, may receive similar inquiries from other regulatory authorities and intend to cooperate fully with any such investigations and inquiries. In response to such FTC investigation or any inquiries EPCO and its affiliates may receive from other regulatory authorities, we may be required to divest certain assets. In the event we are required to divest significant assets, our financial condition could be affected.

 

F-39


Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Relationship with unconsolidated affiliates. Our significant related party transactions with unconsolidated affiliates consist of the sale of natural gas to Evangeline, purchase of pipeline transportation services from Dixie (prior to its consolidation with our results beginning in February 2005, see Note 3) and the purchase of NGL storage, transportation and fractionation services from Promix. In addition, we sell natural gas to Promix and process natural gas at VESCO.

 

9. MINORITY INTEREST

 

Minority interest represents third-party and related party ownership interests in the net assets of certain of our subsidiaries. The following table shows the components of minority interest at the dates indicated:

 

    

March 31,

2005


  

December 31,

2004


EPD’s limited partners

             

Non-affiliates of EPGP Members

   $ 4,421,449    $ 3,992,153

Affiliates of EPGP Members

     811,183      802,505

Joint venture partners

     82,556      71,040
    

  

     $ 5,315,188    $ 4,865,698
    

  

 

The minority interest attributable to EPD’s limited partners consists of EPD common units held by the public, Shell and affiliates of the Company, which primarily includes EPCO, and is net of unamortized deferred compensation of $10.3 million at March 31, 2005 and $10.9 million at December 31, 2004, which represents the value of EPD restricted common units issued to key employees of EPCO. The minority interest attributable to joint venture partners at March 31, 2005 and December 31, 2004, is primarily attributable to our partners in Tri-States, Seminole, Wilprise, Independence Hub and the Mid-America pipeline system. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third-party investor’s ownership in our consolidated balance sheet amounts shown as minority interest.

 

The following table shows distributions paid to and contributions from minority interests attributable to each component of minority interest for the periods indicated:

 

    

For the Three Months

Ended March 31,


 
     2005

    2004

 

Distributions paid to minority interests:

                

EPD’s limited partners

   $ (148,047 )   $ (83,282 )

Joint venture partners

     (1,330 )     (779 )
    


 


     $ (149,377 )   $ (84,061 )
    


 


Contributions from minority interests:

                

EPD’s limited partners

   $ 491,022     $ 22,954  

Joint venture partners

     6,327          
    


 


     $ 497,349     $ 22,954  
    


 


 

Distributions paid to EPD’s limited partners primarily represent the quarterly cash distributions paid by EPD in accordance with their Limited Partnership Agreement. Contributions from EPD’s limited partners primarily represent proceeds received from EPD common unit offerings.

 

F-40


Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

10. CAPITAL STRUCTURE

 

At the dates indicated, our members’ equity account balances and ownership interests were as follows:

 

    

Membership

Percentage at

March 31, 2005


    Members’ Equity Account

      

March 31,

2005


  

December 31,

2004


DFI

   85.60 %   $ 54,196    $ 46,104

DDC

   4.51 %     3,806      3,380

DFI GP

   9.90 %     91,781       

El Paso

                  90,845
          

  

Subtotal

           149,783      140,329

Accumulated Other Comprehensive Income

           22,125      24,554
          

  

Total

         $ 171,908    $ 164,883
          

  

 

Earnings and cash distributions are allocated to Member capital accounts in accordance with their respective membership percentages. On September 30, 2004, El Paso was granted a 9.9% membership interest in the Company in connection with our acquisition of El Paso’s 50% membership interest in GulfTerra GP. In January 2005, DFI GP, an affiliate of EPCO, purchased El Paso’s 9.9% membership interest in us. As a result of these transactions, EPCO and affiliates own 100% of the membership interest in EPGP and, at March 31, 2005, approximately 38.6% of EPD’s total common units outstanding. El Paso no longer owns any interest in EPD or EPGP.

 

F-41


Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

11. DEBT OBLIGATIONS

 

Our debt consisted of the following at the dates indicated:

 

    

March 31,

2005


   

December 31,

2004


 

Operating Partnership debt obligations:

                

364-Day Acquisition Credit Facility, variable rate, repaid in February 2005 (1)

           $ 242,229  

Multi-Year Revolving Credit Facility, variable rate, due September 2009 (2)

   $ 300,000       321,000  

Seminole Notes, 6.67% fixed-rate, due December 2005 (3)

     15,000       15,000  

Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010

     54,000       54,000  

Senior Notes A, 8.25% fixed-rate, repaid March 2005

             350,000  

Senior Notes B, 7.50% fixed-rate, due February 2011

     450,000       450,000  

Senior Notes C, 6.375% fixed-rate, due February 2013

     350,000       350,000  

Senior Notes D, 6.875% fixed-rate, due March 2033

     500,000       500,000  

Senior Notes E, 4.00% fixed-rate, due October 2007

     500,000       500,000  

Senior Notes F, 4.625% fixed-rate, due October 2009

     500,000       500,000  

Senior Notes G, 5.60% fixed-rate, due October 2014

     650,000       650,000  

Senior Notes H, 6.65% fixed-rate, due October 2034

     350,000       350,000  

Senior Notes I, 5.00% fixed-rate, due March 2015

     250,000          

Senior Notes J, 5.75% fixed-rate, due March 2035

     250,000          

Dixie short-term commercial paper debt obligations

     14,000          

GulfTerra Senior Notes and Senior Subordinated Notes (3,4)

     5,719       6,469  

EPGP related party obligation:

                

$370 Million Note, 6.25% fixed rate, due November 2019

     365,409       366,433  
    


 


Total principal amount

     4,554,128       4,655,131  

Other, including unamortized discounts and premiums and changes in fair value

     (31,416 )     (7,462 )
    


 


Subtotal long-term debt

     4,522,712       4,647,669  

Less current maturities of debt (5)

     (32,630 )     (18,450 )
    


 


Long-term debt

   $ 4,490,082     $ 4,629,219  
    


 


Standby letters of credit outstanding (6)

   $ 135,152     $ 139,052  
    


 



(1) We used the proceeds from EPD’s February 2005 common unit offering to fully repay and terminate the 364-Day Acquisition Credit Facility.
(2) The Multi-Year Revolving Credit Facility has a $750 million borrowing capacity, which is reduced by the amount of standby letters of credit outstanding.
(3) Solely as it relates to the assets of our GulfTerra and Seminole subsidiaries, our senior indebtedness is structurally subordinated and ranks junior in right of payment to indebtedness of GulfTerra and Seminole.
(4) GulfTerra’s remaining $0.8 million of 6.25% Senior Notes due June 2010 were called and retired in February 2005.
(5) In accordance with SFAS No. 6, “ Classification of Short-Term Obligations Expected to Be Refinanced ,” long-term and current maturities of debt at December 31, 2004 reflected (i) our refinancing of Senior Notes A with proceeds from our Senior Notes I and J in March 2005 and (ii) the repayment of our 364-Day Acquisition Credit Facility using proceeds from EPD’s equity offering completed in February 2005.

 

F-42


Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

(6) Of the $135 million and $139 million standby letters of credit outstanding at March 31, 2005 and December 31, 2004, $115 million is associated with a letter of credit facility we entered into in November 2004 in connection with our Independence Hub capital project, and the remaining amounts were issued under our Multi-Year Revolving Credit Facility.

 

Parent-Subsidiary guarantor relationships. Through guarantor agreements which are nonrecourse to us, EPD acts as guarantor of the debt obligations of its Operating Partnership, with the exception of the Seminole Notes, Dixie commercial paper obligations and the senior subordinated notes of GulfTerra. If the Operating Partnership were to default on any debt EPD guarantees, EPD would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 88.4% of its capital stock). The senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).

 

Senior Notes E, F, G and H. In September 2004, the Operating Partnership priced a private offering of an aggregate of $2 billion in principal amount of senior unsecured notes in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended, and in October 2004, these notes were issued. On January 24, 2005, we filed a registration statement for an offer to exchange these notes for registered debt securities with identical terms. The exchange of notes was completed in March 2005.

 

Senior Notes I and J. On February 15, 2005, the Operating Partnership sold $500 million in principal amount of senior notes in a Rule 144A private placement offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes (“Senior Notes I”) were issued at 99.379% of their principal amount and have annual fixed-rate interest of 5.00% and a maturity date of March 1, 2015. The 30-year notes (“Senior Note J”) were issued at 98.691% of their principal amount and have annual fixed-rate interest of 5.75% and a maturity date of March 1, 2035. The Operating Partnership used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A which was due on March 15, 2005, and the remaining proceeds for general partnership purposes, including the temporary repayment of indebtedness outstanding under the Multi-Year Revolving Credit Facility.

 

These fixed-rate notes are unsecured obligations of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to us. EPD has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes were issued under an indenture containing certain covenants, which restrict our ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.

 

Dixie short-term commercial paper debt obligations. Dixie has short-term commercial paper obligations that are supported by a $28 million senior unsecured revolving credit facility. The credit facility primarily serves as a backup to the Dixie commercial paper program and may also be used for general corporate purposes. At March 31, 2005, Dixie had an aggregate of $14 million in commercial paper debt obligations outstanding and none under its senior unsecured revolving credit facility. The senior unsecured revolving credit facility contains certain restrictive covenants, which Dixie was in compliance with at March 31, 2005. Both the Dixie commercial paper program and the senior unsecured revolving credit facility are non-recourse to us.

 

Covenants. The Operating Partnership is in compliance with the various covenants of our debt agreements at March 31, 2005 and December 31, 2004.

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Information regarding variable interest rates paid. The following table shows the range of interest rates paid and weighted-average interest rate paid on our significant consolidated variable-rate debt obligations during the three months ended March 31, 2005.

 

    

Range of

interest rates

paid


  

Weighted-

average

interest rate

paid


364-Day Acquisition Credit Facility

   3.25% to 3.40%    3.30%

Multi-Year Revolving Credit Facility

   3.22% to 5.50%    3.42%

 

Consolidated debt maturity table. The following table shows scheduled maturities of the principal amounts of our debt obligations for the next 5 years and in total thereafter.

 

2005

   $ 31,748

2006

     3,802

2007

     504,045

2008

     4,242

2009

     804,576

Thereafter

     3,205,715
    

Total scheduled principal payments

   $ 4,554,128
    

 

Joint venture debt obligations. We have three unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at March 31, 2005, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate at March 31, 2005, on a 100% basis to the joint venture and (iii) the corresponding scheduled maturities of such long-term debt.

 

    

Our

Ownership
Interest


         Scheduled Maturities of Long-Term Debt

       Total

   2005

   2006

   2007

   2008

   2009

   After
2009


Cameron Highway (1)

   50.0 %   $ 325,000           $ 8,125    $ 32,500    $ 192,375    $ 16,000    $ 76,000

Poseidon

   36.0 %     104,000                           104,000              

Evangeline

   49.5 %     35,650    $ 5,000      5,000      5,000      5,000      5,000      10,650
          

  

  

  

  

  

  

Total

         $ 464,650    $ 5,000    $ 13,125    $ 37,500    $ 301,375    $ 21,000    $ 86,650
          

  

  

  

  

  

  


(1) The scheduled maturities for Cameron Highway assume that the construction loan will be converted into a term loan by July 2005 and scheduled repayments will begin on December 31, 2006.

 

In accordance with terms of its credit agreement, Deepwater Gateway had the right to repay the principal amount plus any accrued interest due under its term loan at any time without penalty. During the first quarter of 2005, Deepwater Gateway exercised this right and extinguished its term loan. We and our 50% joint venture partner in Deepwater Gateway, Cal Dive, made equal cash contributions of $72 million to Deepwater Gateway to fund the repayment of the $144 million in principal amount owed under Deepwater Gateway’s term loan.

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

12. SUPPLEMENTAL CASH FLOWS DISCLOSURE

 

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

 

     For the Three Months
Ended March 31,


 
     2005

    2004

 

Decrease (increase) in:

                

Accounts and notes receivable

   $ 150,829     $ 53,952  

Inventories

     (120,178 )     (18,169 )

Prepaid and other current assets

     (16,574 )     (2,296 )

Other assets

     10,226       (53 )

Increase (decrease) in:

                

Accounts payable

     (172,437 )     (22,837 )

Accrued gas payable

     116,962       (34,642 )

Accrued expenses

     (19,438 )     (9,062 )

Accrued interest

     (3,556 )     (30,649 )

Other current liabilities

     1,192       (4,570 )

Other liabilities

     (5,857 )     (273 )
    


 


Net effect of changes in operating accounts

   $ (58,831 )   $ (68,599 )
    


 


 

On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of the capital expenditures associated with such projects. As a result of completing the GulfTerra Merger, the number of such arrangements has increased, particularly for projects involving pipeline construction and production well tie-ins. These reimbursements for the three months ended March 31, 2005 and 2004, were $8.9 million and $0.2 million, respectively, and are reflected as a source of investing cash inflows under the caption “Contributions in aid of construction costs” on our Unaudited Condensed Statements of Consolidated Cash Flows.

 

Net income for the first quarter of 2005 includes a gain on the sale of assets of $5.4 million (recorded as a reduction in operating costs and expenses), which is primarily related to the sale of our 50% interest in Starfish. In connection with gaining regulatory approval for the GulfTerra Merger, we were required to sell our 50% interest in Starfish by March 31, 2005.

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

13. FINANCIAL INSTRUMENTS

 

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

 

Interest rate risk hedging program . Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. As summarized in the following table, we had nine interest rate swap agreements outstanding at March 31, 2005 that were accounted for as fair value hedges.

 

Hedged Fixed Rate Debt


  Number
Of Swaps


 

Period Covered

by Swap


  Termination
Date of Swap


 

Fixed to

Variable Rate (1)


  Notional
Amount


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

  1   Jan. 2004 to Feb. 2011   Feb. 2011   7.50% to 6.3%   $ 50 million

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

  2   Jan. 2004 to Feb. 2013   Feb. 2013   6.375% to 4.9%   $ 200 million

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

  6   4th Qtr. 2004 to Oct. 2014   Oct. 2014   5.6% to 3.4%   $ 600 million

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

 

The total fair value of these nine interest rate swaps at March 31, 2005, was a liability of $18.7 million, with an offsetting decrease in the fair value of the underlying debt. At December 31, 2004, the total fair value of these nine interest rate swaps was an asset of $0.5 million, with an offsetting increase in the fair value of the underlying debt. Interest expense for the three months ended March 31, 2005 and 2004 reflects a benefit of $4.6 million and $1.7 million, respectively, from interest rate swap agreements.

 

During 2004, we entered into two groups of four forward-starting interest rate swap transactions having an aggregate notional amount of $2 billion each in anticipation of our financing activities associated with the closing of the GulfTerra Merger. These interest rate swaps were accounted for as cash flow hedges and were settled during 2004 at a net gain to us of $19.4 million, which will be reclassified from accumulated other comprehensive income to reduce interest expense over the life of the associated debt.

 

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

 

At March 31, 2005 and December 31, 2004, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of natural gas cash flow and fair value hedges. The fair value of our commodity financial instrument portfolio at March 31, 2005 and December 31, 2004 was a liability of $0.5 million and an asset of $0.2 million, respectively. We recorded nominal amounts of earnings from our commodity financial instruments during the three months ended March 31, 2005 and 2004.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

14. BUSINESS SEGMENT INFORMATION

 

Business segments are components of a business about which separate financial information is available. The components are regularly evaluated by our CEO in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments. Our business segments are generally organized and managed according to the type of services rendered and products produced and/or sold, as applicable.

 

We have segregated our business activities into four reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services and Petrochemical Services.

 

The Offshore Pipelines & Services business segment consists of (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 800 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico.

 

The Onshore Natural Gas Pipelines & Services business segment consists of approximately 17,200 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, this segment includes two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast domestic natural gas markets. This segment also includes leased natural gas storage facilities located in Texas and Louisiana.

 

The NGL Pipelines & Services business segment includes our (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,775 miles and related storage facilities, which include our strategic Mid-America and Seminole NGL pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes our import and export terminaling operations.

 

The Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex and an octane additive production facility. This segment also includes various petrochemical pipeline systems.

 

The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings we received from GulfTerra GP. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger. Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours. Since the historical equity earnings of GulfTerra GP were based on net income amounts allocated to it by GulfTerra, it is impractical for us to allocate the equity income we received during the periods presented to each of our new business segments. Therefore, we have segregated equity earnings from GulfTerra GP from our other segment results to aid in comparability between the periods presented.

 

Our revenues are derived from a wide customer base. All consolidated revenues were earned in the United States. Most of our plant-based operations are located either along the western Gulf Coast in Texas, Louisiana and Mississippi or in New Mexico. Our natural gas, NGL and oil pipelines and related operations are in a number of regions of the United States including the Gulf of Mexico offshore Texas and Louisiana; the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and certain regions of the

 

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Index to Financial Statements

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

central and western United States. Our marketing activities are headquartered in Houston, Texas, at our main office and serve customers in a number of regions in the United States including the Gulf Coast, West Coast and Mid-Continent areas.

 

We evaluate segment performance based on segment gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

 

We define total (or consolidated) segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the payment obligation; (3) gains and losses on the sale of assets; and (4) 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 intercompany transactions.

 

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

 

We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers, which may be a supplier of raw materials or a consumer of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations. For example, we use the Promix NGL fractionator to process a portion of the mixed NGLs extracted by our gas plants. Another example was our use of the Dixie pipeline to transport propane sold to customers through our NGL marketing activities (prior to the consolidation of Dixie’s results with ours beginning in February 2005, see Note 3). See Note 8 for additional information regarding our related party relationships with unconsolidated affiliates.

 

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

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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

 

    

For the Three Months

Ended March 31,


 
     2005

    2004

 

Revenues (1)

   $ 2,555,522     $ 1,704,890  

Less operating costs and expenses (1)

     (2,383,644 )     (1,621,508 )

Add: Equity in income of unconsolidated affiliates (1)

     8,279       14,867  

Depreciation and amortization in operating costs and expenses (2)

     99,965       30,520  

Retained lease expense, net in operating expenses allocable to us and minority interest (3)

     528       2,274  

Loss (gain) on sale of assets in operating costs and expenses (2)

     (5,436 )     98  
    


 


Total gross operating margin

   $ 275,214     $ 131,141  
    


 


 
(1) These amounts are taken from our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income.
(2) These non-cash expenses are taken from the operating activities section of our Unaudited Condensed Statements of Consolidated Cash Flows.
(3) These non-cash expenses represent the value of the operating leases contributed by EPCO to us for which EPCO has retained the cash payment obligation (i.e., the “retained leases”). The value of the retained leases contributed directly to us is shown on our Unaudited Condensed Statements of Consolidated Cash Flows under the caption “Operating lease expense paid by EPCO.”

 

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

 

    

For the Three Months

Ended March 31,


 
     2005

    2004

 

Total gross operating margin

   $ 275,214     $ 131,141  

Adjustments to reconcile total gross operating margin to operating income:

                

Depreciation and amortization in operating costs and expenses

     (99,965 )     (30,520 )

Retained lease expense, net in operating costs and expenses

     (528 )     (2,274 )

Gain (loss) on sale of assets in operating costs and expenses

     5,436       (98 )

General and administrative costs

     (15,153 )     (9,498 )
    


 


Consolidated operating income

     165,004       88,751  

Other expense

     (58,128 )     (32,453 )
    


 


Income before provision for income taxes, minority interest and cumulative effect of changes in accounting principles

   $ 106,876     $ 56,298  
    


 


 

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Index to Financial Statements

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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

 

    Operating Segments

             
    Offshore
Pipeline
&
Services


  Onshore
Pipelines
&
Services


  NGL
Pipelines
&
Services


  Petrochem.
Services


  Non-Segmt.
Other


  Adjustments
and
Eliminations


    Consolidated
Totals


Revenues from third parties:

                                           

Three months ended March 31, 2005

  $ 29,548   $ 246,934   $ 1,857,454   $ 363,393                 $ 2,497,329

Three months ended March 31, 2004

          113,026     1,187,574     248,987                   1,549,587

Revenues from related parties:

                                           

Three months ended March 31, 2005

    186     56,215     1,762     30                   58,193

Three months ended March 31, 2004

          47,964     104,931     2,408                   155,303

Intersegment and intrasegment revenues:

                                           

Three months ended March 31, 2005

    196     10,017     729,677     54,750         $ (794,640 )     —  

Three months ended March 31, 2004

          809     447,564     55,311           (503,684 )     —  

Total revenues:

                                           

Three months ended March 31, 2005

    29,930     313,166     2,588,893     418,173           (794,640 )     2,555,522

Three months ended March 31, 2004

          161,799     1,740,069     306,706           (503,684 )     1,704,890

Equity in income in unconsolidated affiliates:

                                           

Three months ended March 31, 2005

    2,975     580     4,448     276                   8,279

Three months ended March 31, 2004

    983     24     2,911     395   $ 10,554             14,867

Gross operating margin by individual business segment and in total:

                                           

Three months ended March 31, 2005

    23,224     79,358     153,304     19,328                   275,214

Three months ended March 31, 2004

    982     5,599     89,955     24,051     10,554             131,141

Segment assets:

                                           

At March 31, 2005

    645,785     3,744,543     2,907,682     464,634           296,603       8,059,247

At December 31, 2004

    648,181     3,729,650     2,753,934     469,327           230,375       7,831,467

Investments in and advances to unconsolidated affiliates:

                                           

At March 31, 2005

    394,337     5,157     137,983     20,502                   557,979

At December 31, 2004

    319,463     5,251     173,883     20,567                   519,164

Intangible Assets:

                                           

At March 31, 2005

    193,325     417,352     298,625     50,835                   960,137

At December 31, 2004

    200,047     425,806     303,424     51,324                   980,601

Goodwill:

                                           

At March 31, 2005

    61,934     288,467     32,603     73,690                   456,694

At December 31, 2004

    62,348     290,397     32,763     73,690                   459,198

 

Revenues from the sale and marketing of NGL products within the NGL Pipelines & Services business segment accounted for 67% and 71% of total consolidated revenues for the three months ended March 31, 2005 and 2004, respectively. Revenues from the sale of petrochemical products within the Petrochemical Services segment accounted for 13% and 12% of total consolidated revenues for the three months ended March 31, 2005 and 2004, respectively. Revenues from onshore transportation and storage of natural gas accounted for 12% of total consolidated revenues for the three months ended March 31, 2005.

 

15. CONDENSED FINANCIAL INFORMATION OF OPERATING PARTNERSHIP

 

The Operating Partnership and its subsidiaries conduct substantially all of our business. Currently, neither we nor EPD have any independent operations or material assets outside of those of the Operating Partnership. EPD acts as guarantor of all the Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes and the remaining amounts outstanding under GulfTerra’s senior subordinated notes. If the Operating Partnership were to default on any debt EPD guarantees, EPD would be responsible for full repayment of that obligation. EPD’s guarantee of these debt obligations is full and unconditional. These debt obligations are non-recourse to us. For additional information regarding our consolidated debt obligations, see Note 11.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The number and dollar amounts of reconciling items between EPD’s consolidated financial statements and those of its Operating Partnership are insignificant. Historically, the primary reconciling items between the consolidated balance sheet of the Operating Partnership and EPD’s consolidated balance sheet were treasury units EPD owns directly and minority interest. The differences in consolidated net income are primarily dividends recognized by the 1999 Trust (which are eliminated in consolidation) and minority interest.

 

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

 

     March 31,
2005


   December 31,
2004


ASSETS              

Current assets

   $ 1,398,265    $ 1,425,574

Property, plant and equipment, net

     8,059,247      7,831,467

Investments in and advances to unconsolidated affiliates, net

     557,979      519,164

Intangible assets, net

     960,137      980,601

Goodwill

     456,694      459,198

Deferred tax asset

     8,915      6,467

Long-term receivables

     15,144      14,931

Other assets

     39,482      43,208
    

  

Total

   $ 11,495,863    $ 11,280,610
    

  

LIABILITIES AND PARTNERS’ EQUITY              

Current liabilities

   $ 1,464,474    $ 1,582,911

Long-term debt

     4,128,303      4,266,236

Other long-term liabilities

     78,195      63,521

Minority interest

     85,372      73,858

Partners’ equity

     5,739,519      5,294,084
    

  

Total

   $ 11,495,863    $ 11,280,610
    

  

Total Operating Partnership debt obligations guaranteed by EPD

   $ 4,154,000    $ 4,267,229
    

  

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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

 

     For the Three Months Ended
March 31,


 
     2005

    2004

 

Revenues

   $ 2,555,522     $ 1,704,890  

Costs and expenses

     2,397,646       1,630,711  

Equity in income of unconsolidated affiliates

     8,279       14,867  
    


 


Operating income

     166,155       89,046  

Other income (expense)

     (52,475 )     (32,299 )
    


 


Income before provision for income taxes, minority

                

interest and changes in accounting principles

     113,680       56,747  

Provision for income taxes

     (1,769 )     (1,625 )
    


 


Income before minority interest and changes in

                

accounting principles

     111,911       55,122  

Minority interest

     (1,941 )     (2,934 )
    


 


Income before changes in accounting principles

     109,970       52,188  

Cumulative effect of changes in accounting principles

             10,781  
    


 


Net income

   $ 109,970     $ 62,969  
    


 


 

16. COMMITMENTS AND CONTINGENCIES

 

Operating leases. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Our material agreements consist of operating leases, with original terms ranging from 5 to 24 years, for natural gas and NGL underground storage facilities. We generally have the option to renew these leases, under the terms of the agreements, for one or more renewal terms ranging from 2 to 10 years. Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. Third-party lease and rental expense included in operating income for the three months ended March 31, 2005 and 2004 was approximately $8.7 million and $4.8 million, respectively.

 

Litigation. We are sometimes named as a defendant in litigation relating to our normal business operations, including litigation related to various federal, state and local regulatory and environmental matters. Although we insure against various business risks, to the extent management believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of ordinary business activity. Management is not aware of any significant litigation, pending or threatened, that would have a significant adverse effect on our financial position or results of operations.

 

We own a facility that historically produced MTBE, a motor gasoline additive that enhances octane and is used in reformulated motor gasoline. We operated the facility, which is located within our Mont Belvieu complex. The production of MTBE was primarily driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990. In recent years, MTBE has been detected in water supplies. The major source of ground water contamination appears to be leaks from underground storage tanks. As a result of environmental concerns, several states enacted legislation to ban or significantly limit the use of MTBE in motor gasoline within their jurisdictions. In addition, federal legislation has been drafted to ban MTBE and replace the oxygenate with renewable fuels such as ethanol.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

A number of lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing MTBE, although generally such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary which owns the facility. It is possible, however, that MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

 

Performance Guaranty. In December 2004, our Independence Hub, LLC subsidiary entered into the Independence Hub Agreement (the “Agreement”) with six oil and natural gas producers. The Agreement obligates Independence Hub, LLC (i) to construct an offshore platform production facility to process 850 MMcf/d of natural gas and condensate and (ii) to process certain natural gas and condensate production of the six producers following construction of the platform facility.

 

In conjunction with the Agreement, our Operating Partnership guaranteed the performance of its Independence Hub, LLC subsidiary under the Agreement up to $397.5 million. In December 2004, 20% of this guaranteed amount was assumed by Cal Dive, our joint venture partner in the Independence Hub project. The remaining $318 million represents our share of the anticipated cost of the platform facility. This amount represents the cap on our Operating Partnership’s potential obligation to the six producers for our share of the cost of constructing the platform in the very unlikely scenario where the six producers take over the construction of the platform facility. Our performance guarantee continues until the earlier to occur of (i) all of the guaranteed obligations of Independence Hub, LLC shall have been terminated or expired, or shall have been indefeasibly paid or otherwise performed or discharged in full, (ii) upon mutual written consent of our Operating Partnership and the producers or (iii) mechanical completion of the production facility. We expect that mechanical completion will occur on or about November 1, 2006; therefore, we anticipate that the performance guaranty will exist until at least this forecast date.

 

In accordance with FIN 45, we recorded the fair value of the performance guaranty using an expected present value approach. Given the remote probability that our Operating Partnership would be required to perform under the guaranty, we have estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of current and other long-term liabilities on our unaudited condensed consolidated balance sheet at March 31, 2005.

 

17. SUBSEQUENT EVENT

 

June 1, 2005 senior notes offering

 

On June 1, 2005, the Operating Partnership sold $500 million in principal amount of 4.95% senior notes due June 2010. The Operating Partnership used the net proceeds of $495.7 million (after deducting applicable underwriting fees, bond discounts and other estimated expenses) from the issuance of these fixed-rate senior notes to temporarily reduce amounts outstanding under the Multi-Year Revolving Credit Facility and for general partnership purposes, including capital expenditures and business combinations.

 

*    *    *    *

 

F-53


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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Board of Directors of

    Enterprise Products GP, LLC

    Houston, Texas

 

We have audited the accompanying consolidated balance sheets of Enterprise Products GP, LLC (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, members’ equity, and cash flows for each of the three years in the period ended December 31, 2004. Our audits also included the financial statement schedule listed in the Index at page F-1. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Enterprise Products GP, LLC and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.

 

/s/    DELOITTE & TOUCHE LLP

 

Houston, Texas

April 25, 2005

 

F-54


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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

 

     December 31,

     2004

   2003

ASSETS              

Current assets

             

Cash and cash equivalents (includes restricted cash of $26,157 at December 31, 2004 and $13,851 at December 31, 2003)

   $ 51,163    $ 44,317

Accounts and notes receivable—trade, net of allowance for doubtful accounts of $24,310 at December 31, 2004 and $20,423 at December 31, 2003

     1,058,375      462,198

Accounts receivable—related parties

     25,151      335

Inventories

     189,019      150,161

Assets held for sale

     36,562       

Prepaid and other current assets

     80,893      30,160
    

  

Total current assets

     1,441,163      687,171

Property, plant and equipment, net

     7,831,467      2,963,505

Investments in and advances to unconsolidated affiliates

     519,164      767,759

Intangible assets, net of accumulated amortization of $74,183 at December 31, 2004 and $40,371 at December 31, 2003

     980,601      268,893

Goodwill

     459,198      82,427

Deferred tax asset

     6,467      10,437

Long-term receivables

     14,931      5,454

Other assets

     62,910      17,156
    

  

Total assets

   $ 11,315,901    $ 4,802,802
    

  

LIABILITIES AND MEMBERS’ EQUITY              

Current liabilities

             

Current maturities of debt

   $ 18,450    $ 240,000

Accounts payable—trade

     203,144      68,384

Accounts payable—related parties

     41,293      40,086

Accrued gas payables

     1,021,294      622,982

Accrued expenses

     130,051      24,696

Accrued interest

     73,151      45,350

Other current liabilities

     104,979      57,900
    

  

Total current liabilities

     1,592,362      1,099,398

Long-term debt

     4,629,219      1,899,548

Other long-term liabilities

     63,739      14,443

Minority interest

     4,865,698      1,752,970

Commitments and contingencies

             

Members’ equity

     164,883      36,443
    

  

Total liabilities and members’ equity

   $ 11,315,901    $ 4,802,802
    

  

 

See Notes to Consolidated Financial Statements

 

F-55


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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

STATEMENTS OF CONSOLIDATED OPERATIONS

AND COMPREHENSIVE INCOME

(Dollars in thousands)

 

     For Year Ended December 31,

 
     2004

    2003

    2002

 

REVENUES

                        

Third parties

   $ 7,517,052     $ 4,782,187     $ 3,102,066  

Related parties

     804,150       564,244       482,717  
    


 


 


Total

     8,321,202       5,346,431       3,584,783  
    


 


 


COST AND EXPENSES

                        

Operating costs and expenses

                        

Third parties

     6,938,768       4,246,122       2,687,260  

Related parties

     965,568       800,655       695,579  
    


 


 


Total operating costs and expenses

     7,904,336       5,046,777       3,382,839  
    


 


 


General and administrative costs

                        

Third parties

     19,157       11,204       19,905  

Related parties

     28,107       27,960       24,204  
    


 


 


Total general and administrative costs

     47,264       39,164       44,109  
    


 


 


Total costs and expenses

     7,951,600       5,085,941       3,426,948  
    


 


 


EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES

     52,787       (13,960 )     35,253  
    


 


 


OPERATING INCOME

     422,389       246,530       193,088  
    


 


 


OTHER INCOME (EXPENSE)

                        

Interest expense

     (155,740 )     (140,806 )     (101,580 )

Interest expense—related parties

     (5,849 )                

Dividend income from unconsolidated affiliates

             5,595       4,737  

Interest income

     2,098       797       2,346  

Other, net

     32       117       350  
    


 


 


Other expense

     (159,459 )     (134,297 )     (94,147 )

INCOME BEFORE PROVISION FOR INCOME TAXES, MINORITY INTEREST AND CHANGES IN ACCOUNTING PRINCIPLES

     262,930       112,233       98,941  

PROVISION FOR INCOME TAXES

     (3,761 )     (5,293 )     (1,634 )
    


 


 


INCOME BEFORE MINORITY INTEREST AND CHANGES IN ACCOUNTING PRINCIPLES

     259,169       106,940       97,307  

MINORITY INTEREST

     (228,716 )     (86,783 )     (86,805 )
    


 


 


INCOME BEFORE CHANGES IN ACCOUNTING PRINCIPLES

     30,453       20,157       10,502  

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES (see Note 1)

     216                  
    


 


 


NET INCOME

     30,669       20,157       10,502  

Cash flow financing hedges

     19,405       5,354       (3,560 )

Reclassification (amortization) of cash flow financing hedges

     (1,275 )     3,196          

Changes in fair value of commodity hedges

     1,434                  
    


 


 


COMPREHENSIVE INCOME

   $ 50,233     $ 28,707     $ 6,942  
    


 


 


 

See Notes to Consolidated Financial Statements

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

STATEMENTS OF CONSOLIDATED CASH FLOWS

(Dollars in Thousands)

 

     For Year Ended December 31,

 
     2004

    2003

    2002

 

OPERATING ACTIVITIES

                        

Net income

   $ 30,669     $ 20,157     $ 10,502  

Adjustments to reconcile net income to cash flows provided by (used for) operating activities:

                        

Depreciation and amortization in operating costs and expenses

     193,734       115,642       86,029  

Depreciation in general and administrative costs

     1,650       159       77  

Amortization in interest expense

     3,503       12,634       8,819  

Equity in (income) loss of unconsolidated affiliates

     (52,787 )     13,960       (35,253 )

Distributions received from unconsolidated affiliates

     68,027       31,882       57,662  

Provision for impairment of long-lived asset

     4,114       1,200          

Cumulative effect of changes in accounting principles

     (216 )                

Operating lease expense paid by EPCO

     7,705       9,094       9,125  

Other expenses paid by EPCO

             443          

Minority interest

     228,716       86,783       86,805  

Gain on sale of assets

     (15,901 )     (16 )     (1 )

Deferred income tax expense

     9,608       10,534       2,080  

Changes in fair market value of financial instruments

     5       (29 )     10,213  

Increase in restricted cash

     (12,305 )     (5,100 )     (2,999 )

Net effect of changes in operating accounts (see Note 16)

     (90,454 )     124,263       93,197  
    


 


 


Cash provided by operating activities

     376,068       421,606       326,256  
    


 


 


INVESTING ACTIVITIES

                        

Capital expenditures

     (155,793 )     (146,790 )     (76,160 )

Contributions in aid of construction

     8,865       877       4,025  

Proceeds from sale of assets

     6,882       212       165  

Cash used for business combinations, net of cash received

     (1,094,661 )     (37,348 )     (1,620,727 )

Acquisition of intangible asset

             (2,000 )     (2,000 )

Investments in and advances to unconsolidated affiliates

     (64,412 )     (471,927 )     (13,651 )
    


 


 


Cash used in investing activities

     (1,299,119 )     (656,976 )     (1,708,348 )
    


 


 


FINANCING ACTIVITIES

                        

Borrowings under debt agreements

     6,304,505       1,926,210       1,968,000  

Repayments of debt

     (5,812,445 )     (2,033,000 )     (637,000 )

Debt issuance costs

     (19,911 )     (8,833 )     (19,329 )

Distributions paid to minority interests

     (404,687 )     (292,351 )     (204,031 )

Contributions from minority interests

     838,541       667,945       178,860  

Distributions paid to Members

     (18,002 )     (19,615 )     (8,000 )

Contributions from Members

     1,791       1,200          

Treasury units reissued (purchased)

     8,394       646       (12,788 )

Settlement of cash flow hedging financial instruments

     19,405       5,354          
    


 


 


Cash provided by financing activities

     917,591       247,556       1,265,712  
    


 


 


NET CHANGE IN CASH AND CASH EQUIVALENTS

     (5,460 )     12,186       (116,380 )

CASH AND CASH EQUIVALENTS, JANUARY 1

     30,466       18,280       134,660  
    


 


 


CASH AND CASH EQUIVALENTS, DECEMBER 31

   $ 25,006     $ 30,466     $ 18,280  
    


 


 


 

See Notes to Consolidated Financial Statements

 

F-57


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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

STATEMENTS OF CONSOLIDATED MEMBERS’ EQUITY

(Dollars in thousands)

 

     DFI

    Shell

    DDC

    El Paso

    Accum.
OCI


    Total

 

Balance, January 1, 2002

   $ 16,404     $ 8,176     $ 2,273                     $ 26,853  

Net income

     6,826       3,151       525                       10,502  

Operating leases paid by EPCO

     119       55       9                       183  

Distributions to members

     (5,200 )     (2,400 )     (400 )                     (8,000 )

Treasury unit transactions:

                                                

—Reissued to satisfy unit options

     (8 )     (3 )     (1 )                     (12 )

Change in fair value of financial instruments recorded as cash flow hedges

                                   $ (3,560 )     (3,560 )
    


 


 


         


 


Balance, December 31, 2002

     18,141       8,979       2,406               (3,560 )     25,966  

Net income

     14,853       4,296       1,008                       20,157  

Operating leases paid by EPCO

     132       41       9                       182  

Other expenses paid by EPCO

     5       3       1                       9  

Contribution from members

     1,140               60                       1,200  

Distributions to members

     (15,904 )     (2,850 )     (861 )                     (19,615 )

EPC Partners II purchase of Shell US Gas and Power’s 30% interest

     10,467       (10,467 )                             —    

Treasury unit transactions:

                                                

—Retired

     (4 )     (2 )                             (6 )

Treasury lock financial instruments recorded as cash flow hedges:

                                                

—Reclassification of change in fair value

                                     3,560       3,560  

—Cash gains on settlement

                                     5,354       5,354  

—Amortization of gain as component of interest expense

                                     (364 )     (364 )
    


 


 


         


 


Balance, December 31, 2003

     28,830       —         2,623               4,990       36,443  

Net income

     28,289               1,489     $ 891               30,669  

Operating leases paid by EPCO

     145               7       2               154  

Contribution from members

     1,533               81       177               1,791  

Distributions to members

     (15,609 )             (821 )     (1,572 )             (18,002 )

Non-cash contribution from EPCO

     2,906                                       2,906  

Proceeds from exercise of EPD unit options

     10               1                       11  

Value of equity interests granted to El Paso

                             91,347               91,347  

Change in fair value of financial instruments

                                     1,434       1,434  

Interest rate hedging financial instruments recorded as cash flow hedges:

                                                

Cash gains on settlement

                                     19,405       19,405  

Amortization of gain as component of interest expense

                                     (1,275 )     (1,275 )
    


 


 


 


 


 


Balance, December 31, 2004

   $ 46,104     $ —       $ 3,380     $ 90,845     $ 24,554     $ 164,883  
    


 


 


 


 


 


 

See Notes to Consolidated Financial Statements

 

F-58


Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

ENTERPRISE PRODUCTS GP, LLC (“EPGP”) is a Delaware limited liability company formed in May 1998 that is the general partner of Enterprise Products Partners L.P. EPGP’s primary business purpose is to manage the affairs and operations of Enterprise Products Partners, L.P. and its subsidiaries (collectively referred to as “EPD”). EPD is a publicly traded Delaware limited partnership listed on the New York Stock Exchange (“NYSE”) under symbol “EPD.” EPD conducts substantially all of its business through its wholly owned subsidiary, Enterprise Products Operating L.P. (the “Operating Partnership”). EPD and the Operating Partnership were formed to acquire, own and operate the natural gas liquids (“NGL”) business of EPCO, Inc. (“EPCO”).

 

Unless the context requires otherwise, references to “we”, “us”, “our”, “EPGP” or the “Company” within these notes shall mean EPGP and its consolidated subsidiaries, which include EPD and its subsidiaries. References to “Shell” shall mean Shell Oil Company, its subsidiaries and affiliates. References to “El Paso” shall mean El Paso Corporation and its affiliates.

 

At December 31, 2004, Duncan Family Interests, Inc. (“DFI”) owned 85.6%, Dan Duncan, LLC (“DDC”) owned 4.5% and El Paso owned 9.9% of the membership interests of EPGP. DFI, DDC and El Paso are collectively referred to as the “Members.” EPCO is the ultimate parent of DFI and an affiliate of DDC. In January 2005, an affiliate of EPCO purchased El Paso’s 9.9% membership interest in us. See Note 20 for additional information regarding this subsequent event.

 

On September 30, 2004, we completed the GulfTerra Merger. For additional information regarding this event, please see Note 4.

 

We own a 2% general partner interest in EPD, which conducts substantially all of our business. We have no independent operations and no material assets outside those of EPD. The number of reconciling items between our consolidated financial statements and those of EPD are few. The primary differences between our consolidated balance sheet and that of EPD are minority interest in our net assets by the limited partners of EPD and the elimination of our investment in EPD with our underlying partner’s capital account in EPD. The difference in consolidated net income is primarily an increase in minority interest expense resulting from the allocation of a portion of our consolidated earnings to the limited partners of EPD.

 

As a result of DFI acquiring Shell’s 30% membership interest in EPGP on September 12, 2003, the financial statements of EPD were consolidated with those of EPGP beginning in September 2003. This accounting consolidation is required because Shell’s minority interest rights in EPGP (which gave them significant participating rights) were terminated as a result of the purchase. This fact, along with DFI’s indirect control of EPD through its common unit holdings, gives EPGP the ability to exercise control over EPD. All significant intercompany accounts and transactions have been eliminated in consolidation. Years prior to 2003 have been presented on a consolidated basis to conform to the current year presentation.

 

The consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after elimination of all material intercompany accounts and transactions. The majority-owned subsidiaries are identified based upon the determination that we possess a controlling financial interest through direct or indirect ownership of a majority voting interest in the subsidiary. Depending on the ownership structure, investments in which we own 3% to 50% and exercise significant influence over operating and financial policies are accounted for using the equity method. Our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates are eliminated in consolidation to the extent such amounts are material and remain on either our or our equity method investees’ balance sheet in inventory or similar accounts.

 

F-59


Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

We have not included earnings per share as we do not have outstanding shares, rather our membership interests are based on ownership percentages.

 

As a result of recently issued accounting guidance under EITF 03-16, the minimum ownership requirement for an investment organized as a limited liability company (“LLC”) to qualify for the equity method of accounting was lowered to between 3% and 5% from the 20% threshold applied to other types of investments. On July 1, 2004, we changed our method of accounting for VESCO from the cost method to the equity method in accordance with EITF 03-16. For additional information regarding this change in accounting method, see Note 7.

 

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

 

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

 

Many of our equity investees are present within our integrated midstream asset system. For example, we have ownership interests in several offshore natural gas and crude oil pipelines through our investments in Poseidon, Cameron Highway, Deepwater Gateway, Neptune and Nemo. We also have a number of investments in NGL transportation or distribution pipelines such as those owned by Belle Rose and Dixie (prior to our purchasing consolidating interests in Dixie in January and February 2005). Other examples include our use of the Promix NGL fractionator to process NGLs extracted by our gas plants. The NGLs received from Promix then can be sold in our NGL marketing activities. Given the integral nature of our equity investees to our operations, we believe treatment of earnings from our equity method investees as a component of gross operating margin and operating income is appropriate. For additional information regarding our investments in and advances to unconsolidated affiliates, please see Note 7. For additional information regarding our business segments, please see Note 18.

 

ASSET RETIREMENT OBLIGATIONS are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development, and/or normal operation. In determining asset retirement obligations, we must identify those legal obligations that we are required to settle as result of existing or enacted law, statute, ordinance, or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel.

 

SFAS No. 143, “ Accounting for Asset Retirement Obligations ,” addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and related asset retirement costs. It requires us to record the fair value of an asset retirement obligation (a liability) in the period in which it is incurred. When a liability is recorded, we will capitalize the cost of the liability by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

capitalized cost is depreciated over the useful life of the related asset. Upon settlement of the liability, we will either settle the obligation for its recorded amount or incur a gain or loss upon settlement. We adopted SFAS No. 143 as of January 1, 2003. See Note 6 for information relating to our asset retirement obligations.

 

CASH FLOWS are computed using the indirect method. For cash flow purposes, we consider all highly liquid investments with an original maturity of less than three months at the date of purchase to be cash equivalents.

 

CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES represents the combined impact of (1) changing the method our BEF subsidiary uses to account for its planned major maintenance activities from the accrue-in-advance method to the expense-as-incurred method and (2) changing the method in which we account for our investment in VESCO from the cost method to the equity method.

 

Our BEF subsidiary owns an octane additive production facility that undergoes periodic planned outages of 30 to 45 days for major maintenance work. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services, and other related items. BEF used the accrue-in-advance method to record cost estimates for such activities; whereas, the Company’s other operations used the expense-as-incurred method for their planned major maintenance activities. Our BEF subsidiary changed its accounting method on January 1, 2004 to conform to the Company’s accounting for planned major maintenance costs, which better reflects expenses in the period incurred. As such, we believe the change is to a method that is preferable in the circumstances. The cumulative effect of this accounting change for years prior to 2004 resulted in a benefit of $7 million ($6.9 million recorded as a reduction to minority interest expense).

 

EITF 03-16 , Accounting for Investments in Limited Liability Companies ,” requires investments in limited liability companies that have separate ownership accounts for each investor be accounted for similar to limited partnerships under SOP No. 78-9, “ Accounting for Investments in Real Estate Ventures .” Under this new guidance (applicable for the period beginning July 1, 2004), investors are required to apply the equity method of accounting to their investments at a much lower ownership threshold (typically any ownership interest greater than 3-5%) than the traditional 20% threshold applied under APB Opinion No. 18, “ The Equity Method of Accounting for Investments in Common Stock .”

 

Prior to July 1, 2004, we accounted for our 13.1% investment in VESCO using the cost method. As a result, we recognized dividend income from VESCO to the extent that we received cash distributions from them. In accordance with the new accounting guidance in EITF 03-16, we recorded a cumulative effect adjustment equal to the difference between (i) equity earnings from VESCO that would have been recorded using the equity method in periods prior to July 1, 2004 and (ii) the dividend income from VESCO we recorded using the cost method in prior periods. The cumulative effect of this accounting change resulted in a benefit of $3.8 million ($3.7 million recorded as a reduction to minority interest expense).

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

For the periods indicated, the following table shows pro forma net income assuming the accounting changes noted above were applied retroactively to January 1, 2002.

 

     For the Year Ended December 31,

 
     2004

    2003

    2002

 

Pro Forma income statement amounts:

                        

Historical net income

   $ 30,669     $ 20,157     $ 10,502  

Adjustments to derive pro forma net income:

                        

Effect of change from the accrue-in-advance method to the expense-as-incurred method for BEF major maintenance costs:

                        

Remove historical equity in (income) losses recorded for BEF

             31,508       (8,569 )

Record equity in (income) losses from BEF calculated using new method of accounting for major maintenance costs

             (31,800 )     8,980  

Remove cumulative effect of change in accounting principle recorded on January 1, 2004

     (140 )                

Effect of changing from the cost method to the equity method with respect to our investment in VESCO:

                        

Remove cumulative effect of change in accounting principle recorded on July 1, 2004

     (76 )                

Remove historical dividend income recorded from VESCO

     (2,136 )     (5,595 )     (4,737 )

Record equity earnings from VESCO

     2,429       5,133       12,303  

Effect of changes on minority interest of EPGP

     (287 )     739       (7,817 )
    


 


 


Pro forma net income

   $ 30,459     $ 20,142     $ 10,662  
    


 


 


 

DOLLAR AMOUNTS presented in the tabulations within the notes to our financial statements are stated in thousands of dollars, unless otherwise indicated.

 

ENVIRONMENTAL COSTS for remediation are accrued based on the estimates of known remediation requirements. Such accruals are based on management’s estimate of the ultimate costs to remediate the site. Ongoing environmental compliance costs are charged to expense as incurred, and expenditures to mitigate or prevent future environmental contamination are capitalized. Environmental costs and related accruals were not significant prior to the GulfTerra Merger. As a result of the GulfTerra Merger, we have initially estimated an environmental liability of $21 million, which is included in other long-term liabilities on our Consolidated Balance Sheet at December 31, 2004, for remediation costs expected to be incurred over time associated with mercury gas meters. Costs of environmental compliance and monitoring aggregated $1.9 million, $1.6 million and $1.7 million for the years ended December 31, 2004, 2003 and 2002, respectively.

 

EXCESS COST OVER UNDERLYING EQUITY IN NET ASSETS (or “excess cost”) denotes the excess of our cost (or purchase price) over our underlying equity in the net assets of our investees. At December 31, 2004, our investments in Promix, La Porte, Dixie, Neptune, Poseidon, Cameron Highway and Nemo included excess cost. The excess cost of these investments is reflected in our investments in and advances to unconsolidated affiliates for these entities.

 

We evaluate equity method investments (which include excess cost amounts attributable to tangible or intangible assets) for impairment whenever events or changes in circumstances indicate that there is a loss in value of the investment which is an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the investee or long-term negative changes in the investee’s

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

industry. In the event that we determine that the loss in value of an investment is other than a temporary decline, we would record a charge to earnings to adjust the carrying value to fair value. See Note 7 for a further discussion of the excess cost related to these investments.

 

EXCHANGES are contractual agreements for the movements of NGL and petrochemical products between parties to satisfy timing and logistical needs of the parties. Net exchange volumes borrowed from us under such agreements are valued and included in accounts receivable, and net exchange volumes loaned to us under such agreements are valued and accrued as a liability in accrued gas payables.

 

EXIT AND DISPOSAL COSTS are those charges associated with an exit activity that does not involve an entity newly acquired in a business combination or with a disposal activity covered by SFAS No. 144, “ Accounting for the Impairment or Disposal of Long-Lived Assets. ” Examples of these costs include (i) termination benefits provided to current employees that are involuntarily terminated under the terms of a benefit arrangement that, in substance, is not an ongoing benefit arrangement or an individual deferred compensation contract, (ii) costs to terminate a contract that is not a capital lease, and (iii) costs to consolidate facilities or relocate employees. In accordance with SFAS No. 146, “ Accounting for Costs Associated with Exit and Disposal Activities ,” we recognize such costs when they are incurred rather than at the date of our commitment to an exit or disposal plan. We adopted SFAS No. 146 on January 1, 2003. Our adoption of this standard has had no material impact on our financial statements.

 

FINANCIAL INSTRUMENTS such as swaps, forward and other contracts to manage the price risks associated with inventories, firm commitments, interest rates and certain anticipated transactions are used by the Company. We recognize our transactions on the balance sheet as assets and liabilities based on the 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. If the financial instruments meet those criteria, the instrument’s gains and losses offset related results of the hedge item in the income statement for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses on cash flow hedges are reclassified into earnings when the forecasted transaction occurs or, as appropriate, over the depreciable life of the underlying asset. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.

 

To qualify as a hedge, the item to be hedged must expose us to commodity or interest rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS No. 133, “ Accounting for Derivative Instruments and Hedging Activities ” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness is recorded into earnings immediately. See Note 17 for a further discussion of our financial instruments.

 

GOODWILL represents the excess of amounts we paid for businesses and assets over the respective fair value of the underlying net assets purchased (see Note 8). Since adopting SFAS No. 142, “ Goodwill and Other Intangible Assets ”, on January 1, 2002, our goodwill amounts are no longer amortized but are assessed annually for recoverability. In addition, we periodically review the reporting units to which the goodwill amounts relate if impairment indicators are evident. If such indicators are present (i.e., loss of a significant customer, economic obsolescence of plant assets, etc.), the fair value of the reporting unit, including its related goodwill, will be calculated and compared to its combined book value. If the fair value of the reporting unit exceeds its book value, goodwill is not considered impaired and no adjustment to earnings would be required. Should the fair value of the reporting unit (including its goodwill) be less than its book value, a charge to earnings would be recorded to adjust goodwill to its implied fair value. We have not recognized any impairment losses related to our goodwill for any of the periods presented.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

INTANGIBLE ASSETS consist primarily of the estimated value assigned to certain customer relationships and certain customer contracts (see Note 8). Our customer relationship intangible assets represent the customer base that GulfTerra and the South Texas midstream assets serve through providing services, including natural gas gathering and processing, NGL fractionation and pipeline transportation. These entities conduct the majority of their business through regular contact and the use of written contracts. The value of these customer relationships are being amortized using expected production curves associated with the underlying resource bases (i.e., the oil and gas reserves associated with the intangible assets). Our estimate of the economic life of each resource base is based on a number of factors, including third-party reserve estimates, the economic viability of production and exploration activities and other industry factors.

 

Our contract-based intangible assets represent the rights we own arising from contractual agreements primarily within our natural gas and NGL operations. A contract-based intangible asset with a finite useful life is amortized over its estimated useful life based on the respective contract terms. Our estimate of useful life is also based on a number of factors, including the expected useful life of related assets (i.e., fractionation facility, pipeline, etc.) and the effects of obsolescence, demand, competition and other factors.

 

INVENTORIES primarily consist of NGL, petrochemical and natural gas volumes and are valued at the lower of average cost or market (see Note 5). Shipping and handling charges directly related to volumes we purchase or to which we take ownership are capitalized as costs of inventory. As these inventories are sold and delivered out of inventory, the average cost of these products (which includes freight-in charges which have been capitalized) are charged to current period operating costs and expenses. Shipping and handling charges for products we sell and deliver to customers are charged to operating costs and expenses as incurred.

 

Costs and expenses, as shown on our Statements of Consolidated Operations and Comprehensive Income, include costs of sales related to inventories. For the years ended December 31, 2004, 2003 and 2002, such consolidated cost of sales amounts were $7.2 billion, $4.5 billion and $3 billion, respectively.

 

LONG-LIVED ASSETS (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.

 

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with SFAS No. 144 “ Accounting for the Impairment or Disposal of Long-Lived Assets .” Under SFAS No. 144, an asset shall be tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows.

 

In order to complete the GulfTerra Merger, the FTC required us to sell our interest in a Mississippi propane storage facility in which we owned a 50% interest. As a result of our determination of this long-lived asset’s current market value, we recorded a $4 million non-cash asset impairment charge during the third quarter of 2004, which is reflected a component of operating costs and expenses on our 2004 Statement of Consolidated Operations.

 

Additionally, during 2003 we recorded a $1.2 million asset impairment charge related to our Petal NGL fractionator. This non-cash amount is a component of operating costs and expenses as shown on our 2003 Statement of Consolidated Operations. The Petal NGL fractionation facility was decommissioned in December

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

2003 after management decided that this older facility did not fit into our long-range plans due to poor economics of continued operations at the site. We continue to own this facility, the carrying value of which has been adjusted to its fair value of approximately $0.1 million. We did not recognize any impairment losses during 2002.

 

NATURAL GAS IMBALANCES result when a customer delivers more or less gas into our pipelines than they take out. We generally value our imbalances using a twelve-month moving average of natural gas prices, which we believe is an appropriate assumption to estimate the value of the imbalances upon settlement given that the actual settlement dates may vary by customer. Changes in natural gas prices may impact our estimates. Prior to the GulfTerra Merger, natural gas imbalances were not significant.

 

At December 31, 2004, our imbalance receivables were $56.7 million and are reflected as a component of “Accounts receivable—trade” on our Consolidated Balance Sheet. At December 31, 2004, our imbalance payables were $59 million and are reflected as a component of “Accrued gas payables” on our Consolidated Balance Sheet.

 

PROPERTY, PLANT AND EQUIPMENT is recorded at its original cost of construction or, upon acquisition, the fair value of the asset acquired. Our property, plant and equipment is generally depreciated using the straight-line method over the asset’s estimated useful life. Maintenance, repairs and minor renewals are charged to operations as incurred. The cost of assets retired or sold, together with the related accumulated depreciation, is removed from the accounts. Any gain or loss on disposition is included in operating income.

 

Additions and improvements to and major renewals of existing assets are capitalized and depreciated using the straight-line method over the estimated useful life of the new equipment or modifications. These expenditures result in a long-term benefit to Enterprise. See Note 6 for additional information regarding our property, plant and equipment.

 

We use the expense-as-incurred method for our planned major maintenance activities. Prior to January 1, 2004, BEF, which became a majority owned consolidated subsidiary on September 30, 2003, used the accrue-in-advance method for its planned major maintenance costs. On January 1, 2004, BEF elected to change its method of accounting for these costs to the expense-as-incurred method. As a result, our consolidated statement of operations for 2004 reflect the cumulative effect of change in accounting method associated with the removal of BEF’s $7.0 million liability for accrued costs for planned future major maintenance activities.

 

PROVISION FOR INCOME TAXES is primarily applicable to certain federal and/or state tax obligations of our Mid-America and Seminole pipelines. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities for financial reporting and tax purposes. See Note 12 for additional information regarding our provision of income taxes.

 

In general, EPD’s limited partnership structure is not subject to federal income taxes. As a result, its earnings or losses for federal income tax purposes are included in the tax returns of the individual partners. On a stand alone basis, EPGP (a limited liability company) was organized as a pass-through entity for federal income tax purposes. As a result, for federal income tax purposes, the Members are individually responsible for taxes of their allocable share of the taxable income of EPGP.

 

RESTRICTED CASH includes amounts held by a brokerage firm as margin deposits associated with our financial instruments portfolio and for physical purchase transactions made on the NYMEX exchange. At December 31, 2004 and 2003, cash and cash equivalents includes, $26.2 million and $13.9 million of restricted cash related to these requirements, respectively.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

REVENUE is recognized using the following criteria: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyer’s price is fixed or determinable and (iv) collectibility is reasonably assured. See Note 3 for additional information regarding our revenue recognition process.

 

When the contracts settle (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed), a determination of the necessity of an allowance is made and recorded accordingly. Our allowance for doubtful accounts amount is generally determined as a percentage of revenues for the last twelve months. Our procedure for recording an allowance for doubtful accounts is based on historical experience, financial stability of our customers and levels of credit granted to customers. In addition, we may also increase the allowance account in response to specific identification of customers involved in bankruptcy proceedings and those experiencing financial uncertainties. We routinely review our estimates in this area to ascertain that we have recorded sufficient reserves to cover forecasted losses. Our allowance for doubtful accounts was $24.3 million and $20.4 million at December 31, 2004 and 2003, respectively.

 

A substantial portion of our revenues are derived from various companies in the domestic natural gas, NGL and petrochemical industry. This concentration could affect our overall exposure to credit risk since these customers might be affected by similar economic or other conditions. We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults.

 

UNIT OPTION PLAN ACCOUNTING is based on the intrinsic-value method described in APB No. 25, “ Accounting for Stock Issued to Employees ” for EPCO employees working on behalf of EPD. We use the provisions of SFAS No. 123, “ Accounting for Stock-Based Compensation ,” to account for unit options granted to our non-employee directors.

 

Under the intrinsic-value method described in APB No. 25, EPD does not record compensation expense related to options granted when the exercise price is equal to or greater than the market price of the underlying equity on the date of grant. In accordance with SFAS No. 148, “ Accounting for Stock-Based Compensation—Transition and Disclosure, ” we disclose the pro forma effect on our earnings as if the fair-value method of SFAS No. 123, “Accounting for Stock-Based Compensation” had been used instead of the intrinsic-value of APB No. 25 to account for such options. The effects of applying SFAS No. 123 in the following pro forma disclosure may not be indicative of future amounts as additional awards in future years are anticipated. The following table shows the pro forma effects for the periods indicated.

 

     For Year Ended December 31,

 
     2004

    2003

    2002

 

Historical net income

   $ 30,669     $ 20,157     $ 10,502  

Additional unit option-based compensation expense estimated using fair value-based method

     (932 )     (1,107 )     (2,077 )
    


 


 


Pro forma net income

   $ 29,737     $ 19,050     $ 8,425  
    


 


 


Unit option-based compensation expense included in the determination of net income as reported

   $ 60     $ 71     $ 62  
    


 


 


 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The fair value of each EPD option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions:

 

     2004

    2003

    2002

 

Expected life of options

   7 years     7 years     7 years  

Risk-free interest rate

   3.99 %   3.79 %   3.10 %

Expected dividend yield

   8.78 %   9.12 %   5.65 %

Expected Unit price volatility

   29 %   29 %   25 %

 

USE OF ESTIMATES AND ASSUMPTIONS by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period are required for the preparation of financial statements in conformity with accounting principles generally accepted in the United States of America. Our actual results could differ from these estimates.

 

2. RECENT ACCOUNTING DEVELOPMENTS

 

FIN 46, Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51. ” This interpretation of ARB No. 51 addresses requirements for accounting consolidation of a variable interest entity (“VIE”) with its primary beneficiary. In general, if the equity owner of a VIE meets certain criteria defined within FIN 46, the assets, liabilities and results of the activities of the VIE should be included in the consolidated financial statements of the owner. Our adoption of FIN 46 (as amended by FIN 46R) in 2003 has had no material effect on our consolidated financial statements. Due to the complexity of FIN 46 (as amended by FIN 46R and interpreted), the FASB is continuing to provide guidance regarding implementation issues. Since this guidance is still continuing, our conclusions regarding the application of this guidance may be altered. As a result, adjustments may be recorded in future periods as we adopt new FASB interpretations of FIN 46.

 

SFAS No. 151, “Inventory Costs—an Amendment of ARB No. 43, Chapter 4.” This accounting guidance, which is applicable for fiscal years beginning after June 15, 2005, amends ARB No. 43, Chapter 4, to clarify that abnormal amounts of idle facility expense, freight, handling costs and wasted materials (spoilage) should be recognized as current period charges. It also requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. We do not expect the adoption of SFAS No. 151 to have a material impact on our financial position, results of operations or cash flows.

 

SFAS No. 123(R), “Share-Based Payment.” This accounting guidance, which is applicable for the first interim or annual reporting period beginning after June 15, 2005, replaces SFAS No. 123, “ Accounting for Stock-Based Compensation ” and supersedes APB No. 25, “ Accounting for Stock Issued to Employees .” This Statement eliminates the ability to account for share-based compensation transactions using APB No. 25, and generally requires instead that such transactions be accounted for using a fair-value-based method.

 

This statement requires a public entity, such as EPD, to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award—the requisite service period (usually the vesting period). No compensation cost is recognized for equity instruments for which employees do not render the requisite service. Employee share purchase plans will not result in recognition of compensation cost if certain conditions are met; those conditions are much the same as the related conditions in SFAS No. 123.

 

A public entity will initially measure the cost of employee services received in exchange for an award of liability instruments based on its current fair value; the fair value of that award will be remeasured subsequently

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

at each reporting date through the settlement date. Changes in fair value during the requisite service period will be recognized as compensation cost over that period.

 

The grant-date fair value of employee share options and similar instruments will be estimated using option-pricing models adjusted for the unique characteristics of those instruments (unless observable market prices for the same or similar instruments are available). If an equity award is modified after the grant date, incremental compensation cost will be recognized in an amount equal to the excess of the fair value of the modified award over the fair value of the original award immediately before the modification.

 

EPD is continuing to evaluate the provisions of SFAS No. 123(R) and will fully adopt the standard on January 1, 2006. Upon the required effective date, EPD will apply this statement using a modified version of prospective application as described in the standard.

 

FIN 47. “Accounting for Conditional Asset Retirement Obligations.” Under SFAS No. 143, a company must record a liability for its legal obligations stemming from the eventual retirement of its tangible long-lived assets, whether that obligation results from the acquisition, construction, or development of the asset. However, many companies have not recorded a liability, concluding that either (1) the conditional nature of the obligation does not create a liability until the retirement activity occurs or (2) the timing and/or the method of settling the obligation is unknown. This Interpretation concludes otherwise. If required legally, an obligation associated with the asset’s retirement is inevitable even though uncertainties exist about the timing and/or method of settling the obligation. According to the Interpretation, these uncertainties affect the fair value of the liability, rather than obviate the need to record one at all. Additionally, the ability of a company to postpone indefinitely settlement of the obligation, or to sell the asset prior to its retirement, does not relieve a company of its present duty to settle the obligation. We are currently studying the effects of the adoption of this Interpretation which we will adopt in December 2005.

 

3. REVENUE RECOGNITION

 

The following summarizes our consolidated revenue recognition policies by business segment, which are generally organized according to the type of services rendered and products produced and/or sold:

 

Offshore Pipelines & Services . Revenues from our offshore natural gas pipelines are derived from fee-based contracts and are typically based on transportation fees per unit of volume (typically in MMBtus) transported multiplied by the volume delivered. Revenues are recognized when volumes have been physically delivered for the customer through the pipeline.

 

Revenues from the majority of our offshore crude oil pipelines are derived from purchase and sale arrangements whereby we purchase oil from shippers at various receipt points on our crude oil pipelines for an index-based price, less a price differential, and sell the oil back to the shippers at various redelivery points at the index-based price. The net revenue from these arrangements are based on the price differential (difference between the purchase and sales price) per unit of volume (typically in barrels) multiplied by the volume delivered. Revenues associated with these purchase and sale arrangements are recorded as net revenue and are recognized when we complete the delivery of crude oil to the purchaser. Revenues from some of our offshore crude oil pipelines are based upon a gathering fee per unit of volume (typically in barrels) multiplied by the volume delivered. Revenues from the gathering fees we charge for our services are dependent on the volume of crude oil to be delivered and the amount and term of the reserve commitment by the customer.

 

Under our platform services contracts, there are typically two components of revenues, a demand fee which is typically a fixed-fee charged to a customer using our platform services regardless of the volume the customer delivers to the platform, and a commodity charge which is typically a fixed-fee per MMcf of natural gas or barrel of crude oil, whichever the case may be, multiplied by the volume delivered to our platform by the customer.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Contracts for platform services often include both demand fees and commodity charges, but demand fees generally expire after a contractual fixed period of time. Revenues for platform services, including both demand fees and commodity charges, are recognized in the period the services are provided.

 

Onshore Natural Gas Pipelines & Services . Revenues from some of our onshore natural gas pipelines are derived from fee-based contracts and are typically based upon a transportation fee per unit of volume (generally in MMBtus) transported multiplied by the volume delivered. The transportation fee is generally contractual or as regulated by various governmental agencies, including the FERC. Revenues associated with these fee-based contracts are recognized when volumes have been physically delivered to our customer through the pipeline. Additionally, we have product sales contracts associated with some of our onshore natural gas pipelines whereby revenue is recognized when we sell and deliver a volume of natural gas to a customer. Revenues from these natural gas sales contracts are based upon market-related prices as determined by the individual agreements.

 

Under our natural gas storage contracts, there are typically two components of revenues, fixed monthly demand payments, which are associated with storage capacity reservation and paid regardless of the customer’s usage of the storage facilities, and storage fees per unit of volume stored at the facilities. Revenues from demand payments are recognized throughout the period in which the capacity is reserved by the customer, and revenues from storage fees associated with volumes stored at our facilities are recognized in the period the services are provided.

 

NGL Pipelines & Services . In our natural gas processing activities, we enter into margin-band contracts, percent-of-liquids contracts, fee-based contracts, hybrid contracts (mixed percent-of-liquids and fee-based) and keepwhole contracts. The most significant contract affecting our natural gas processing business is the Shell agreement, which is a margin-band arrangement, which grants us the right to process Shell’s current and future production within state and federal waters of the Gulf of Mexico. Under margin-band and keepwhole contracts, we take ownership of mixed NGLs extracted from the producer’s natural gas stream and recognize revenue when the extracted NGLs are delivered and sold to customers on NGL marketing sales contracts. In the same way, revenue is recognized under our percent-of-liquids contracts except that the volume of NGLs we extract and sell is less than the total amount of NGLs extracted from the producers’ natural gas. Under a percent-of-liquids contract, the producer retains title to the remaining percentage of mixed NGLs we extract. If a cash fee for natural gas processing services is stipulated by the contract, we record revenue when the natural gas has been processed and delivered to the producer.

 

Our NGL marketing activities within this segment use product sales contracts with various customers to sell and deliver NGLs as a result of our keepwhole and percent-of-liquids arrangements and those it purchases from third parties in the open market. These NGL sales contracts may include forward product sales contracts from time-to-time. Revenues from NGL sales contracts are recognized and recorded upon the delivery of the NGL products to our customers. Pricing for these sales contracts is based upon market-related prices and can include pricing differentials due to factors such as differing delivery locations.

 

Under our NGL transportation contracts, revenue is recognized when volumes have been physically delivered to our customer through the pipeline. Revenue from these contracts is generally based upon a fixed fee per gallon of liquids transported, multiplied by the volume delivered. The fixed fee is generally contractual or as required by various governmental agencies, including the FERC.

 

Under our NGL and related product storage contracts, we collect a fee based on the number of days a customer has NGL or petrochemical volumes in storage multiplied by a storage rate for each product. Under these contracts, revenue is recognized ratably over the length of the storage period based on the storage fees specified in each contract.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Revenues from product terminaling contracts (applicable to our import and export operations) are recorded when services have been performed. In our export operations, we record revenues related to demand fees collected from exporters and shippers in the event they contract for use of our facilities and later fail to do so. The demand fees are contractual and vary by agreement. We recognize revenue from contractual demand fees after the exporter or shipper fails to utilize our facilities as required by contract.

 

We also enter into NGL fractionation fee-based arrangements and NGL fractionation percent-of-liquids contracts. Under our fee-based arrangements, we recognize revenue upon completion of all contract services and obligations. These fee-based arrangements typically include a base-processing fee (typically in cents per gallon) subject to adjustment for changes in certain of our fractionation expenses, including natural gas fuel costs. For some of our NGL fractionation facilities, we utilize percent-of-liquids contracts. A percent-of-liquids processing contract allows us to retain a contractually determined percentage of NGL products fractionated for our customer in lieu of collecting a cash-tolling fee per gallon.

 

Petrochemical Services . We enter into isomerization and propylene fractionation fee-based processing arrangements and petrochemical product sales contracts. Under our processing arrangements, we recognize revenue upon completion of all contract processing services and obligations. These processing arrangements typically include a base-processing fee per gallon (or other unit of measurement) subject to adjustment for changes in natural gas, electricity and labor costs, which are the primary variable costs of fractionation and isomerization operations.

 

In our petrochemical product sales contracts, we recognize revenue when the products have been delivered to the customer. Pricing for sales contracts is based upon market-related prices as determined by the individual agreements.

 

Consolidated revenues compared to segment revenues . Segment revenues include intersegment and intrasegment revenues, which are generally based on transactions made at market-related rates. Our consolidated revenues reflect the elimination of all material intercompany (both intersegment and intrasegment) transactions. See Note 18 for additional information regarding intersegment and intrasegment revenues and a reconciliation of total segment revenues to total consolidated revenues.

 

4. BUSINESS COMBINATIONS

 

Acquisition of 50% membership interest in general partner of GulfTerra

 

Immediately prior to closing the GulfTerra Merger on September 30, 2004 (see below), we acquired El Paso’s 50% membership interest in GulfTerra Energy Company, L.L.C., the general partner of GulfTerra (“GulfTerra GP”), for $370 million in cash and the issuance of a 9.9% membership interest in the Company to El Paso. Subsequently, we contributed this 50% membership interest in GulfTerra GP to EPD without the receipt of additional general partner interest, common units or other consideration. We borrowed the $370 million used to acquire this interest from DDC, which obtained the funds through a loan from EPCO (which indirectly owns an 85.595% membership interest in us through DFI).

 

The fair value we assigned to the 50% membership interest in GulfTerra GP we acquired is based on 50% of an implied $922.7 million estimated total fair value of GulfTerra GP, which assumes that the $370 million cash payment made to El Paso represented consideration for a 40.1% interest in GulfTerra GP. The 40.1% interest was derived by deducting the 9.9% membership interest we granted to El Paso in this transaction from the 50% membership interest in GulfTerra GP that we received. The preliminary fair value of $461.3 million assigned to this voting membership interest compares favorably to the $425 million that EPD paid El Paso to purchase a 50%

 

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non-voting membership interest in GulfTerra GP in December 2003. We valued the 9.9% membership interest we granted to El Paso at $91.3 million, which equals the difference between the $461.3 preliminary fair value of the GulfTerra GP interest we acquired and the $370 million cash payment we made to El Paso.

 

Completion of the GulfTerra Merger by EPD

 

On September 30, 2004, EPD and GulfTerra completed the merger of GulfTerra with a wholly owned subsidiary of EPD. Additionally, EPD completed certain other transactions related to the merger, including receipt of Enterprise GP’s contribution of a 50% membership interest in GulfTerra GP (as discussed in the previous section of this Note 4) and the purchase of certain midstream energy assets located in South Texas from El Paso. The aggregate value of the total consideration EPD paid or issued to complete the GulfTerra Merger was approximately $4 billion. These transactions were recorded using purchase accounting.

 

Since the GulfTerra Merger closed on September 30, 2004, our Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2004, includes three months of results of operations from the GulfTerra assets. The effective closing date of our purchase of the South Texas midstream assets was September 1, 2004. As a result, our Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2004, includes four months of results of operations from the South Texas midstream assets.

 

As a result of the GulfTerra Merger, GulfTerra and GulfTerra GP became wholly owned subsidiaries of EPD on September 30, 2004. On October 1, 2004, we contributed our ownership interests in GulfTerra and GulfTerra GP to the Operating Partnership, which resulted in GulfTerra and GulfTerra GP becoming wholly owned subsidiaries of the Operating Partnership.

 

Formed in 1993, GulfTerra manages a balanced, diversified portfolio of interests and assets relating to the midstream energy sector, which involves gathering, transporting, separating, processing, fractionating and storing natural gas, oil and NGLs. GulfTerra’s interests and assets included (i) offshore oil and natural gas pipelines, platforms, processing facilities and other energy infrastructure in the Gulf of Mexico, primarily offshore Louisiana and Texas; (ii) onshore natural gas pipelines and processing facilities in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas; (iii) onshore NGL pipelines and fractionation facilities in Texas; and (iv) onshore natural gas and NGL storage facilities in Louisiana, Mississippi and Texas.

 

The South Texas midstream assets consisted of nine natural gas processing plants with a combined capacity of 1.9 Bcf/d, a 294-mile natural gas gathering system, a natural gas treating facility with a capacity of 150 MMcf/d and a small NGL pipeline.

 

The GulfTerra Merger transactions

 

The GulfTerra Merger occurred in several interrelated transactions as described below.

 

    Step One . On December 15, 2003, EPD purchased a 50% membership interest in GulfTerra GP from El Paso for $425 million in cash. GulfTerra GP owns a 1% general partner interest in GulfTerra. Prior to completion of the GulfTerra Merger, EPD accounted for its investment in GulfTerra GP using the equity method of accounting. The $425 million in funds required to complete Step One were borrowed under an Interim Term Loan and pre-merger revolving credit facilities. This amount was fully repaid with the net proceeds from equity offerings EPD completed during 2004.

 

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    Step Two . On September 30, 2004, the GulfTerra Merger was consummated and GulfTerra and GulfTerra GP became wholly owned subsidiaries of EPD. Step Two of the GulfTerra Merger included the following transactions:

 

    As discussed previously in this Note 4, we acquired El Paso’s remaining 50% membership interest in GulfTerra GP for $370 million in cash paid to El Paso and the issuance of a 9.9% membership interest in Enterprise GP to El Paso. Subsequently, we contributed this 50% membership interest in GulfTerra GP to EPD without the receipt of additional general partner interest, common units or other consideration.

 

    Immediately prior to closing the GulfTerra Merger, EPD paid $500 million in cash to El Paso for 10,937,500 Series C units of GulfTerra and 2,876,620 common units of GulfTerra. The remaining 57,762,369 GulfTerra common units (7,433,425 of which were owned by El Paso) were converted into 104,549,823 EPD common units (13,454,499 of which are held by El Paso) at the time of the consummation of the GulfTerra Merger.

 

    Step Three . Immediately after Step Two was completed, EPD acquired certain South Texas midstream assets from El Paso for $155.3 million in cash. Pursuant to written agreements, EPD’s purchase of the South Texas midstream assets was effective September 1, 2004.

 

In connection with the closing of the GulfTerra Merger, on September 30, 2004, the Operating Partnership borrowed an aggregate $2.8 billion under its new revolving credit facilities in order to fund its cash payment obligations under Step Two and Step Three of the GulfTerra Merger and related transactions, including the tender offers for GulfTerra’s outstanding senior and senior subordinated notes. See Note 9 for a description of these new borrowing and debt-related transactions.

 

In January 2005, an affiliate of EPCO, acquired El Paso’s 9.9% membership interest in the Company and 13,454,499 of EPD’s common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and affiliates own 100% of the membership interests of the Company and, at March 15, 2005, approximately 38.3% of EPD’s total common units outstanding. El Paso no longer owns any interest in EPD or EPGP.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The total consideration EPD and EPGP paid or granted for the GulfTerra Merger is summarized below:

 

Step One transaction:

        

Cash payment by EPD to El Paso for initial 50% membership interest in GulfTerra GP (a non-voting interest) made in December 2003

   $ 425,000  
    


Total Step One consideration

     425,000  
    


Step Two transactions:

        

Cash payment by EPD to El Paso for 10,937,500 GulfTerra Series C units and 2,876,620 GulfTerra common units

     500,000  

Fair value of EPD equity interests granted to acquire remaining 50% membership interest in GulfTerra GP (voting interest) and cash payment of $370 million by EPGP to El Paso

     461,347  

Fair value of EPD common units issued in exchange for remaining GulfTerra common units

     2,445,420  

Fair value of other EPD equity interests granted for unit awards and Series F2 convertible units

     4,004  

Fair value of receivable from El Paso for transition support payments (1)

     (40,313 )

Transaction fees and other direct costs incurred by EPD as a result of the GulfTerra Merger (2)

     24,032  
    


Total Step Two consideration

     3,394,490  
    


Total Step One and Step Two consideration

     3,819,490  
    


Step Three transaction:

        

Purchase of South Texas midstream assets from El Paso

     155,277  
    


Total consideration for Steps One through Three

   $ 3,974,767  
    



(1) Reflects the present value of a contract-based receivable from El Paso received as part of the negotiated net consideration reached in Step One of the GulfTerra Merger. The agreements between Enterprise and El Paso provide that for a period of three years following the closing of the GulfTerra Merger, El Paso will make transition support payments to Enterprise in annual amounts of $18 million, $15 million and $12 million for the first, second and third years of such period, respectively, payable in twelve equal monthly installments for each such year. The $45 million receivable from El Paso has been discounted to fair value and recorded as a reduction in the purchase consideration for GulfTerra. As December 31, 2004, the fair value of the current portion and non-current portion of this contract-based receivable was $17.2 million and $23.1 million, respectively; these amounts are reflected as a component of “Prepaid and other current assets” and “Long-term receivables” on our Consolidated Balance Sheet as of December 31, 2004.
(2) As a result of the GulfTerra Merger, Enterprise incurred expenses of approximately $24 million for various transaction fees and other direct costs. These direct costs include fees for legal, accounting, printing, financial advisory and other services rendered by third-parties to Enterprise over the course of the GulfTerra Merger transactions. This amount also includes $3.4 million of involuntary severance costs.

 

In connection with the GulfTerra Merger, we are required under a consent decree to sell our 50% interest in Starfish, which owns the Stingray natural gas pipeline and related gathering pipelines and dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana. In January 2005, we entered into a contract with a third party to sell this investment for approximately $41.2 million, and we closed the sale on March 31, 2005. The sale required FTC approval under the terms of the consent decree relating to the GulfTerra Merger. Additionally, under the same consent decree, we were required to sell our undivided 50% interest in a Mississippi propane storage facility by December 31, 2004. We sold our interest in this facility during the fourth quarter of 2004.

 

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Other business combinations and asset acquisitions completed during 2004

 

During 2004, we also acquired an additional 16.7% interest in Tri-States; an additional 10% interest in Seminole; the remaining 33.3% ownership interest in BEF; and certain assets located in Morgan’s Point, Texas.

 

Acquisition of 16.7% interest in Tri-States . On April 1, 2004, we acquired an additional 16.7% membership interest in Tri-States, which owns an NGL pipeline located along the Mississippi, Alabama and Louisiana Gulf Coast. This system, in conjunction with the Wilprise and Belle Rose NGL pipelines, transport mixed NGLs to the BRF, Norco and Promix NGL fractionators located in south Louisiana. Due to this acquisition, our ownership interest in Tri-States increased to 66.7% and Tri-States became a majority-owned consolidated subsidiary of ours on April 1, 2004. Previously, Tri-States was accounted for as an equity method unconsolidated affiliate.

 

Acquisition of 10% interest in Seminole . On May 31, 2004, we acquired an additional 10% interest in Seminole, which owns a regulated 1,281-mile pipeline that transports mixed NGLs and NGL products from the Hobbs hub on the Texas-New Mexico border and the Permian Basin area to southeast Texas. As a result of this acquisition, our ownership interest in Seminole increased to 88.4%. The Seminole pipeline is interconnected with our Mid-America pipeline system at the Hobbs hub. The primary source of throughput for Seminole is volume originating from the Mid-America system.

 

Acquisition of remaining 33.3% interest in BEF . On September 1, 2004, we acquired the remaining 33.3% ownership interest in BEF, which owns a facility that produces octane additives such as MTBE (a motor gasoline additive that enhances octane and is used in reformulated gasoline). As a result of this acquisition, BEF became a wholly owned subsidiary of ours.

 

Acquisition of Morgan’s Point assets . On December 13, 2004, we acquired certain assets located in Morgan’s Point, Texas. The assets acquired primarily include an octane enhancement facility, a butane isomerization facility, a barge dock and NGL and petrochemical pipelines.

 

Allocation of purchase price of 2004 business combinations

 

The GulfTerra Merger transactions and our other business and asset acquisitions completed during 2004 were recorded using the purchase method of accounting. Purchase accounting requires us to allocate the cost of a business combination to the assets acquired and liabilities assumed based on their estimated fair values. We engaged an independent third-party business valuation expert to assess the fair values of the tangible and intangible assets of GulfTerra, the South Texas midstream assets, and those acquired in the Morgan’s Point transaction. This information will assist management in the development of a definitive allocation of the overall purchase price of the GulfTerra Merger transactions. Management independently developed the fair value estimates for the other 2004 business acquisitions using recognized business valuation techniques.

 

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The preliminary fair values shown in the following table are estimates based on information available to EPD at December 31, 2004. The valuation estimates shown below could change due to this recent transaction and the refinement of our estimates. See Note 16 for the effects these business combinations had on EPGP’s consolidated balance sheet at December 31, 2004.

 

     Merger-Related Transactions

             
     Step Two of
GulfTerra
Merger


   

Step Three
Purchase of

South Texas

Midstream
Assets


    Other 2004
Acquisitions


    Total

 

Purchase price allocation:

                                

Assets acquired in business combination:

                                

Current assets, including cash of $40,453

   $ 198,347     $ 7,614     $ 10,374     $ 216,335  

Property, plant and equipment, net

     4,601,390       112,830       92,721       4,806,941  

Investments in and advances to unconsolidated affiliates

     202,672               (42,597 )     160,075  

Intangible assets

     705,459       37,802       1,092       744,353  

Other assets

     26,881                       26,881  
    


 


 


 


Total assets acquired

     5,734,749       158,246       61,590       5,954,585  
    


 


 


 


Liabilities assumed in business combination:

                                

Current liabilities

     (228,566 )     (2,969 )     (2,329 )     (233,864 )

Long-term debt, including current maturities

     (2,015,583 )                     (2,015,583 )

Other long-term liabilities

     (47,880 )                     (47,880 )

Minority interest

                     26,590       26,590  
    


 


 


 


Total liabilities assumed

     (2,292,029 )     (2,969 )     24,261       (2,270,737 )
    


 


 


 


Total assets acquired less liabilities assumed

     3,442,720       155,277       85,851       3,683,848  

Total consideration given

     3,819,490       155,277       85,851       4,060,618  
    


 


 


 


Remaining Goodwill

   $ 376,770     $ —       $ —       $ 376,770  
    


 


 


 


 

As a result of the preliminary purchase price allocation for Steps Two and Three of the GulfTerra Merger, we recorded $744.4 million of amortizable intangible assets, primarily those related to customer relationships and contracts. The remaining preliminary amount represents goodwill of $376.8 million associated with our view of the future results from GulfTerra’s operations, based on the strategic location of GulfTerra’s assets as well as their industry relationships. For additional information regarding these intangible assets and goodwill, see Note 8. For the recent GulfTerra Merger and the related South Texas midstream assets, the allocation of the purchase price to the estimated fair values of assets and liabilities is based, in part, upon assistance from an independent third party business valuation expert. In addition, the Morgan’s Point allocation (which is a component of “Other 2004 Acquisitions” as shown in the preceding table), is preliminary. Such preliminary values are subject to final valuation reports and additional information.

 

Pro forma financial information

 

The following table presents selected unaudited pro forma financial information incorporating the historical (pre-merger) results of GulfTerra, the South Texas midstream assets and our other business acquisitions. Since the GulfTerra Merger closed on September 30, 2004, our Statements of Consolidated Operations and Comprehensive Income do not include any earnings from GulfTerra prior to October 1, 2004. The effective closing date of our purchase of the South Texas midstream assets was September 1, 2004. As a result, our

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Statements of Consolidated Operations and Comprehensive Income for the year ended December 31, 2004 include four months of results of operations from the South Texas midstream assets. The results of operations of our other business acquisitions are also included in our Statements of Consolidated Operations from the date of acquisition.

 

The following pro forma information has been prepared as if the GulfTerra Merger and our other business combination transactions had been completed on January 1, 2003 as opposed to the actual dates that these acquisitions occurred. The pro forma information is based upon data currently available and includes certain estimates and assumptions made by management. As a result, this pro forma information is not necessarily indicative of our financial results had the transactions actually occurred on this date. Likewise, the following unaudited pro forma financial information is not necessarily indicative of our future financial results (dollars in millions).

 

     For the Year Ended
December 31,


     2004

   2003

Pro forma earnings data:

             

Revenues

   $ 9,615.1    $ 7,153.0

Costs and expenses

   $ 9,065.0    $ 6,727.5

Operating income

   $ 575.0    $ 419.6

Income before extraordinary items

   $ 31.1    $ 20.4

Net income

   $ 31.1    $ 20.4

 

5. INVENTORIES

 

Our inventories consisted of the following at the dates indicated:

 

     December 31,

     2004

   2003

Working inventory

   $ 171,485    $ 135,451

Forward-sales inventory

     17,534      14,710
    

  

Inventory

   $ 189,019    $ 150,161
    

  

 

A general description of our inventories is as follows:

 

    Our regular trade (or “working”) inventory is comprised of inventories of natural gas, NGLs and petrochemical products that are available for sale or used in the provision of services. This inventory is valued at the lower of average cost or market, with “market” being determined by industry-related posted prices such as those published by OPIS and CMAI.

 

    The forward-sales inventory is comprised of segregated NGL volumes dedicated to the fulfillment of forward sales contracts and is valued at the lower of average cost or market, with “market” being defined as the weighted-average sales price for NGL volumes to be delivered in future months on the forward sales contracts.

 

In general, our inventory values reflect amounts we have paid for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection and demurrage charges and other handling and processing costs. In those instances where we take ownership of inventory volumes through percent-of-liquids and similar arrangements (as opposed to actually purchasing volumes for cash from third parties, see Note 3), these volumes are valued at market-related prices during the month in which they are

 

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acquired. Like the third-party purchases described above, we inventory the various ancillary costs such as freight-in and other handling and processing amounts associated with owned volumes obtained through our in-kind and similar contracts.

 

Due to fluctuating market conditions in the NGL, natural gas and petrochemical industry, we occasionally recognize lower of average cost or market (“LCM”) adjustments when the cost of our inventories exceed their net realizable value. These non-cash adjustments are charged to operating costs and expenses in the period they are recognized and generally affect our segment operating results in the following manner:

 

    NGL inventory write-downs are recorded as a cost of the Processing segment’s NGL marketing activities;

 

    Natural gas inventory write downs are recorded as a cost of the Pipeline segment’s Acadian Gas operations; and

 

    Petrochemical inventory write downs are recorded as a cost of the Fractionation segment’s petrochemical marketing activities or as a cost of the Octane Enhancement segment’s MTBE operations, as applicable.

 

For the years ended December 31, 2004, 2003 and 2002, we recognized LCM adjustments of approximately $9.4 million, $16.9 million and $6.3 million, respectively. The majority of these write-downs were taken against NGL inventories. To the extent our commodity hedging strategies address inventory-related risks and are successful, these inventory valuation adjustments are mitigated (or in some cases, offset). See Note 17 for a description of our commodity hedging activities.

 

6. PROPERTY, PLANT AND EQUIPMENT

 

Our property, plant and equipment and accumulated depreciation were as follows at the dates indicated:

 

    

Estimated
Useful Life

in Years


    At December 31,

       2004

   2003

Plants and pipelines (1)

   5-35  (5)   $ 7,691,197    $ 3,214,463

Underground and other storage facilities (2)

   5-35  (6)     531,394      288,199

Platforms and facilities (3)

   23-31       162,645       

Transportation equipment (4)

   3-10       7,240      5,676

Land

           29,142      23,447

Construction in progress

           230,375      74,431
          

  

Total

           8,651,993      3,606,216

Less accumulated depreciation

           820,526      642,711
          

  

Property, plant and equipment, net

         $ 7,831,467    $ 2,963,505
          

  


(1) Plants and pipelines includes processing plants; NGL, petrochemical, oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment; and related assets.
(2) Underground and other storage facilities includes underground product storage caverns; storage tanks; water wells; and related assets.
(3) Platforms and facilities includes offshore platforms and related facilities and other associated assets.
(4) Transportation equipment includes vehicles and similar assets used in our operations.

 

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(5) In general, the estimated useful lives of major components of this category are: processing plants, 20-35 years; pipelines, 18-35 years (with some equipment at 5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings 20-35 years; and laboratory and shop equipment, 5-35 years.
(6) In general, the estimated useful lives of major components of this category are: underground storage facilities, 20-35 years (with some components at 5 years); storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years).

 

Depreciation expense for the years ended December 31, 2004, 2003 and 2002 was $161 million, $101 million and $72.5 million, respectively. The significant portion of the year-to-year increase in depreciation expense is attributable to acquisitions we completed during each period. The year-to-year increase in depreciation expense for 2004 and 2003 is primarily due to the property, plant and equipment assets we acquired in the GulfTerra Merger, which were recorded at their preliminary fair values upon completion of the GulfTerra Merger at September 30, 2004 (see Note 4).

 

Capitalized interest on our construction projects for the years ended December 31, 2004, 2003 and 2002 was $2.8 million, $1.6 million and $1.1 million, respectively.

 

Asset retirement obligations . SFAS No. 143 establishes accounting standards for the recognition and measurement of an ARO liability and the associated asset retirement cost. As a result of the GulfTerra Merger, we assumed AROs associated with the future retirement obligations for certain limited offshore assets located in the Gulf of Mexico. The aggregate $6.2 million liability associated with this ARO is a component of “Other Long-Term Liabilities” on our Consolidated Balance Sheet at December 31, 2004.

 

In addition to the obligations we assumed in the GulfTerra Merger, we have also identified ARO liabilities in our other operational areas. These include ARO liabilities related to (i) right-of-way easements over property not owned by us and (ii) regulatory requirements triggered by the abandonment or retirement of certain currently operated facilities. As a result of our analysis of these identified AROs, we were not required to recognize such potential liabilities. Our rights under the easements are renewable and only require retirement action upon nonrenewal of the easement agreements. We currently expect to renew all such easement agreements and to use these properties for the foreseeable future. Should we decide not to renew these right-of-way agreements, an ARO liability would be recorded at that time. We also identified potential ARO liabilities arising from regulatory requirements related to the future abandonment or retirement of certain currently operated facilities. At present, we currently have no intention or legal obligation to abandon or retire such facilities. An ARO liability would be recorded if future abandonment or retirement of such facilities occurred.

 

Certain of our unconsolidated affiliates, Deepwater Gateway, Neptune, Nemo, and Starfish, had recorded ARO’s at December 31, 2004 relating to regulatory requirements. These amounts are immaterial to our financial statements and had a negligible effect on our equity earnings from these investments during 2004.

 

7. INVESTMENTS IN AND ADVANCES TO UNCONSOLIDATED AFFILIATES

 

We own interests in a number of related businesses that are accounted for using the equity method. In general, we use the equity method of accounting for an investment in which we own 20% to 50% of its outstanding ownership interests and exercise significant influence over its operating and financial policies. We do not exercise management control over our equity or cost method investees. As a result of recently issued accounting guidance under EITF 03-16 (see Note 1), the minimum ownership requirement for an investment organized as a limited liability company (or “LLC”) to qualify for the equity method of accounting was lowered to between 3% and 5% from the 20% threshold applied to other types of investments.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

On July 1, 2004, we changed our method of accounting for VESCO from the cost method to the equity method in accordance with EITF 03-16. Our VESCO investment consists of a 13.1% interest in a LLC that owns a natural gas processing plant, NGL fractionation facilities, storage assets and gas gathering pipelines located in south Louisiana. For additional information regarding this change in accounting method, see Note 1.

 

Our investments in and advances to these unconsolidated affiliates are grouped in the following table according to the business segment to which they relate. For a general discussion of our business segments, see Note 18.

 

    

Ownership
Percentage at

December 31,
2004


    Investments in and advances to
Unconsolidated Affiliates at


       December 31,
2004


   December 31,
2003


Offshore Pipeline & Services:

                   

Poseidon (1)

   36.0 %   $ 63,944       

Cameron Highway (1)

   50.0 %     114,354       

Deepwater Gateway (1)

   50.0 %     56,527       

Offshore pipeline investments (2)

   Various       84,638    $ 127,605

Onshore Natural Gas Pipeline & Services:

                   

Evangeline

   49.5 %     2,810      2,519

Coyote (1)

   50.0 %     2,441       

NGL Pipeline & Services:

                   

Dixie

   19.9 %     32,514      35,988

VESCO

   13.1 %     38,437      33,000

Belle Rose

   41.7 %     10,172      10,780

Promix

   50.0 %     65,748      38,903

BRF

   32.3 %     27,012      27,892

Tri-States (3)

                  44,119

Petrochemical Services:

                   

BRPC

   30.0 %     15,617      16,584

La Porte

   50.0 %     4,950      5,422

Other:

                   

GulfTerra GP (4)

                  424,947
          

  

Total

         $ 519,164    $ 767,759
          

  


(1) Our ownership interest in these investments was acquired in connection with the GulfTerra Merger on September 30, 2004.
(2) Reflects our collective investment in Neptune, Nemo and Starfish. In connection with the GulfTerra Merger, we were required under a consent decree published for comment by the FTC on September 30, 2004 to sell our 50% ownership interest in Starfish. The carrying value of our investment in Starfish was reclassified from “Investments in and Advances to Unconsolidated Affiliates” to “Assets Held for Sale” on our Consolidated Balance Sheet at December 31, 2004. On March 31, 2005, we sold our ownership interest in Starfish to a third party.
(3) We acquired an additional 16.7% ownership interest in Tri-States in April 2004. As a result of this acquisition, Tri-States became a consolidated subsidiary.
(4) In connection with the GulfTerra Merger (see Note 4), GulfTerra GP became a wholly owned consolidated subsidiary on September 30, 2004. We had previously accounted for our 50% ownership interest in GulfTerra GP as an equity method investment from December 15, 2003 through September 29, 2004.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

On occasion, the price we pay to acquire an investment exceeds the underlying historical net assets (i.e., the underlying equity account balances on the books of the investee) that we purchase. These excess cost amounts are a component of our investments in and advances to unconsolidated affiliates. At December 31, 2004, our investments in Promix, La Porte, Dixie, Neptune, Poseidon, Cameron Highway and Nemo included excess cost. An analysis of each of these investments at the time of purchase indicated that such excess cost amounts were attributable to either (i) an increase in the fair value of the tangible assets owned by each entity over the investee’s historical carrying values or (ii) it was unattributable to other specific assets (including intangible assets) and was deemed to be goodwill. To the extent that we attribute an excess cost amount to tangible or intangible assets, we amortize these amounts as a reduction in equity earnings in a manner similar to depreciation. To the extent we attribute an excess cost amount to goodwill, we do not amortize this amount but it is subject to evaluation for impairment. At December 31, 2004, excess cost amounts included in our investments in and advances to unconsolidated affiliates totaled $83.6 million, of which $74.3 million was attributed to tangible assets and the remainder to goodwill. Amortization of our excess cost amounts attributed to tangible assets was $1.9 million, $1.6 million, and $1.6 million during 2004, 2003 and 2002, respectively.

 

The following table shows our equity in income (loss) of unconsolidated affiliates for the periods indicated:

 

     For the Year Ended December 31,

 
     2004

    2003

    2002

 

Offshore Pipeline & Services:

                        

Poseidon

   $ 2,509                  

Cameron Highway

     (461 )                

Deepwater Gateway

     3,562                  

Offshore pipeline investments (1)

     3,249     $ 5,561     $ 10,534  

Onshore Natural Gas Pipeline & Services:

                        

Coyote

     541                  

Evangeline

     231       131       (58 )

NGL Pipelines & Services:

                        

Dixie

     1,273       1,323       1,231  

VESCO

     6,132       —         —    

Belle Rose

     (402 )     (55 )     203  

Promix

     859       2,106       3,936  

BRF

     2,190       832       2,427  

Tri-States (2)

     (154 )     1,542       1,959  

Wilprise (2)

             276       948  

EPIK (2)

             1,818       4,688  

Petrochemical Services:

                        

BRPC

     1,943       1,198       997  

La Porte

     (710 )     (698 )     (559 )

BEF (2)

             (27,864 )     8,569  

OTC (2)

             (77 )     378  

Other:

                        

Gulf Terra GP (3)

     32,025       (53 )        
    


 


 


Total

   $ 52,787     $ (13,960 )   $ 35,253  
    


 


 



(1) Reflects combined equity earnings from Neptune, Nemo and Starfish. In connection with the GulfTerra Merger, we were required under a consent decree published for comment by the FTC on September 30, 2004 to sell our 50% interest in Starfish. On March 31, 2005, we sold our ownership interest in Starfish to a third party.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

(2) We acquired additional ownership interests in or control over these entities since January 1, 2003 resulting in our consolidation of each company’s post-acquisition financial results with those of our own. Our consolidation of each company’s post-acquisition financial results began in the following periods: EPIK, March 2003; Wilprise, October 2003; OTC, August 2003; BEF, September 2003; and Tri-States, April 2004.
(3) In connection with the GulfTerra Merger (see Note 4), GulfTerra GP became a wholly owned consolidated subsidiary on September 30, 2004. We had previously accounted for our 50% ownership interest in GulfTerra GP as an equity method investment from December 15, 2003 through September 29, 2004.

 

Offshore Pipelines & Services segment

 

At December 31, 2004, our Offshore Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

 

    Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)—a 36% interest in Poseidon, which owns a crude oil pipeline extending from the Gulf of Mexico to onshore Louisiana. Poseidon completed construction of its Front Runner oil pipeline in the third quarter of 2004 and received its first volumes from this new oil pipeline in January 2005. This new oil pipeline connects the Front Runner platform in the Gulf of Mexico with Poseidon’s existing system.

 

    Cameron Highway Oil Pipeline Company (“Cameron Highway”)—a 50% interest in Cameron Highway, which owns a recently constructed crude oil pipeline system that connects various designated crude oil receipt points extending from Ship Shoal Block 332 in the Gulf of Mexico to onshore delivery points located in the state of Texas. We anticipate that operations will commence on this pipeline system in early 2005.

 

    Deepwater Gateway, L.L.C. (“Deepwater Gateway”)—a 50% interest in Deepwater Gateway, which owns the Marco Polo tension-leg platform. The Marco Polo tension-leg platform is operated by Anadarko Petroleum Corporation (“Anadarko”) and processes oil and natural gas from Anadarko’s Marco Polo Field discovery located at Green Canyon Block 608 in the Gulf of Mexico. The Marco Polo tension-leg platform went into service during the third quarter of 2004.

 

    Offshore pipeline investments —our collective investment in Neptune Pipeline Company, L.L.C. (“Neptune”), Nemo Gathering Company, LLC (“Nemo”) and Starfish Pipeline Company, LLC (“Starfish”). We own a 25.7% interest in Neptune, which owns the Manta Ray and Nautilus natural gas pipeline systems located in the Gulf of Mexico offshore Louisiana. In addition, we own a 33.9% interest in Nemo, which owns the Nemo natural gas pipeline located in the Gulf of Mexico offshore Louisiana. This category also includes our 50% interest in Starfish, which owns the Stingray and Triton natural gas pipeline and related dehydration and other facilities located in south Louisiana and the Gulf of Mexico. In connection with the GulfTerra Merger, we were required under a consent decree published for comment by the FTC on September 30, 2004 to sell our 50% interest in Starfish by March 31, 2005. In January 2005, we entered into a contract with a third party to sell this investment for approximately $42.1 million, and we closed the sale on March 31, 2005. The sale required FTC approval under the terms of the consent decree relating to the GulfTerra Merger.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s unconsolidated affiliates are summarized below.

 

     At December 31,

    
     2004

   2003

    

BALANCE SHEET DATA:

                    

Current assets

   $ 79,196    $ 93,277       

Property, plant and equipment, net

     712,182      711,853       

Other assets

     528,443      277,205       
    

  

      

Total assets

   $ 1,319,821    $ 1,082,335       
    

  

      

Current liabilities

   $ 71,758    $ 64,585       

Other liabilities

     526,990      404,170       

Combined equity

     721,073      613,580       
    

  

      

Total liabilities and combined equity

   $ 1,319,821    $ 1,082,335       
    

  

      
     For Year Ended December 31,

     2004

   2003

   2002

INCOME STATEMENT DATA:

                    

Revenues

   $ 88,603    $ 76,168    $ 90,924

Operating income

     46,938      39,658      54,752

Net income

     38,473      33,700      73,509

 

Onshore Natural Gas Pipelines & Services segment

 

At December 31, 2004, our Onshore Natural Gas Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

 

    Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively, “Evangeline”)—an approximate 49.5% aggregate interest in a natural gas pipeline system located in south Louisiana.

 

    Coyote Gas Treating, LLC (“Coyote”)—a 50% interest in Coyote, which owns a natural gas treating facility located in the San Juan Basin of southwestern Colorado.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s unconsolidated affiliates are summarized below.

 

     At December 31,

    
     2004

   2003

    

BALANCE SHEET DATA:

                  

Current assets

   $ 21,652    $ 14,120     

Property, plant and equipment, net

     38,821      40,994     

Other assets

     35,149      38,865     
    

  

    

Total assets

   $ 95,622    $ 93,979     
    

  

    

Current liabilities

   $ 24,365    $ 16,782     

Other liabilities

     37,210      41,906     

Combined equity

     34,047      35,291     
    

  

    

Total liabilities and combined equity

   $ 95,622    $ 93,979     
    

  

    

 

     For Year Ended December 31,

     2004

   2003

   2002

INCOME STATEMENT DATA:

                    

Revenues

   $ 257,539    $ 230,429    $ 145,289

Operating income

     8,552      9,275      4,394

Net income

     4,657      5,037      251

 

NGL Pipelines & Services segment

 

At December 31, 2004, our NGL Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:

 

    Dixie Pipeline Company (“Dixie”)—an aggregate 19.9% interest in a 1,301-mile propane pipeline and associated facilities extending from Mont Belvieu, Texas to North Carolina.

 

    Venice Energy Services Company, LLC (“VESCO”)—a 13.1% interest in a natural gas processing plant, fractionation facilities, storage, and gas gathering pipelines located in southern Louisiana and, with respect to certain of the gas gathering pipelines, also in the Gulf of Mexico. On July 1, 2004, we changed our method of accounting for VESCO from the cost method to the equity method in accordance with EITF 03-16 (see Note 1).

 

    Belle Rose NGL Pipeline LLC (“Belle Rose”)—a 41.7% interest in an NGL pipeline system located in south Louisiana.

 

    K/D/S Promix LLC (“Promix”)—a 50% interest in an NGL fractionator and related storage and pipeline assets located in south Louisiana. In December 2004, we acquired an additional 16.7% ownership interest in Promix from Koch. As a result of this purchase, our ownership interest in Promix increased to 50%.

 

    Baton Rouge Fractionators LLC (“BRF”)—an approximate 32.3% interest in an NGL fractionator located in southeastern Louisiana.

 

In March 2003, we purchased the remaining ownership interests in EPIK Terminalling L.P. and EPIK Gas Liquids, LLC (collectively, “EPIK”), at which time EPIK became a consolidated subsidiary of ours. In October 2003, we purchased an additional 37.4% interest in Wilprise Pipeline Company, LLC (“Wilprise”), at which time it became a 74.7% owned consolidated subsidiary of ours. In April 2004, we purchased an additional 16.7% interest in Tri-States NGL Pipeline LLC (“Tri-States”), at which time it became a 66.7% owned consolidated subsidiary of ours. See Note 4 for additional information regarding our business combinations.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s unconsolidated affiliates are summarized below.

 

     At December 31,

     2004

   2003

BALANCE SHEET DATA:

             

Current assets

   $ 101,660    $ 59,206

Property, plant and equipment, net

     399,580      433,841

Other assets

     16,993      4,304
    

  

Total assets

   $ 518,233    $ 497,351
    

  

Current liabilities

   $ 95,537    $ 54,195

Other liabilities

     13,422      107,938

Combined equity

     409,274      335,218
    

  

Total liabilities and combined equity

   $ 518,233    $ 497,351
    

  

 

     For Year Ended December 31,

     2004

   2003

   2002

INCOME STATEMENT DATA:

                    

Revenues

   $ 298,061    $ 314,837    $ 287,236

Operating income

     57,134      51,844      53,477

Net income

     50,523      45,129      47,279

 

Petrochemical Services segment

 

At December 31, 2004, our Petrochemical Services segment included the following unconsolidated affiliates accounted for using the equity method:

 

    Baton Rouge Propylene Concentrator, LLC (“BRPC”)—a 30% interest in a propylene fractionator located in southeastern Louisiana.

 

    La Porte Pipeline Company, L.P. and La Porte Pipeline GP, LLC (collectively “La Porte”)—an aggregate 50% interest in a polymer grade propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas.

 

In November 2003, we purchased the remaining 50% of outstanding common stock of Olefins Terminal Corporation (“OTC”). As a result, OTC became a wholly owned subsidiary of ours. See Note 4 for additional information regarding our business combinations.

 

In September 2003, we acquired an additional 33.3% interest in Belvieu Environmental Fuels (“BEF”), which owns a facility that historically produced MTBE, a motor gasoline additive that enhanced octane values and is used in reformulated motor gasoline. As a result of this acquisition, BEF became a majority-owned consolidated subsidiary of ours on September 30, 2003. Previously, BEF was accounted for as an equity-method unconsolidated affiliate. In September 2004, we acquired the remaining 33.3% interest in BEF.

 

As a result of declining domestic demand and a prolonged period of weak MTBE production economics, several of BEF’s competitors announced their withdrawal from the marketplace during 2003. Due to the deteriorating business environment and outlook and the completion of its preliminary engineering studies regarding conversion alternatives, BEF evaluated the carrying value of its long-lived assets for impairment during the third quarter of 2003. This review indicated that the carrying value of its long-lived assets exceeded

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

their collective fair value, which resulted in a non-cash asset impairment charge of $67.5 million. Our share of this loss was $22.5 million and is recorded as a component of “Equity in loss of unconsolidated affiliates” in our Statements of Consolidated Operations and Comprehensive Income for the year ended December 31, 2003.

 

BEF’s assets were written down to fair value, which was determined by independent appraisers using present value techniques. The impaired assets principally represent the plant facility and other assets associated with MTBE production. The fair value analysis incorporates probability-weighted cash flows for future courses of action being taken (or contemplated to be taken) by BEF management, including modification of the facility to produce iso-octane and alkylate. If the underlying assumptions in the fair value analysis change resulting in the present value of expected future cash flows being less than the new carrying value of the facility, additional impairment charges may result in the future. See Note 15 for additional information regarding risks associated with our investment in BEF.

 

The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s unconsolidated affiliates are summarized below.

 

     At December 31,

    
     2004

   2003

    

BALANCE SHEET DATA:

                    

Current assets

   $ 3,266    $ 4,007       

Property, plant and equipment, net

     57,516      61,162       
    

  

      

Total assets

   $ 60,782    $ 65,169       
    

  

      

Current liabilities

   $ 438    $ 1,224       

Combined equity

     60,344      63,945       
    

  

      

Total liabilities and combined equity

   $ 60,782    $ 65,169       
    

  

      
     For Year Ended December 31,

     2004

   2003

   2002

INCOME STATEMENT DATA:

                    

Revenues

   $ 18,378    $ 14,512    $ 12,209

Operating income

     5,131      2,726      2,232

Net income

     5,151      2,685      2,243

 

Other, non-segment

 

The Other, non-segment category is presented for financial reporting purposes only to show the historical equity earnings we received from our 50% membership interest in the general partner of GulfTerra, GulfTerra Energy Company, L.L.C . (“GulfTerra GP”), which owns a 1.0% general partner interest in GulfTerra. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger (see Note 4). Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours. Since the historical equity earnings of GulfTerra GP were based on net income amounts allocated to it by GulfTerra, it is impractical for us to allocate the equity income we received during the periods presented to each of our new segments. Therefore, we have segregated equity earnings from GulfTerra GP apart from our other investments to aid in comparability between the periods presented and future periods.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

8. INTANGIBLE ASSETS AND GOODWILL

 

Intangible assets. The following table summarizes our intangible assets at the dates indicated:

 

          At December 31, 2004

   At December 31, 2003

    

Gross

Value


   Accum.
Amort.


    Carrying
Value


   Accum.
Amort.


    Carrying
Value


Offshore Pipelines & Services:

                                    

Offshore pipeline & platform customer relationships (1)

   $ 205,845    $ (6,965 )   $ 198,880               

Independence Hub

     1,167              1,167               
    

  


 

              

Segment total

     207,012      (6,965 )     200,047               
    

  


 

              

Onshore Natural Gas Pipelines & Services:

                                    

San Juan Gathering System customer relationships (1)

     331,311      (6,222 )     325,089               

Permian Basin customer relationships (1)

     1,590      (57 )     1,533               

Petal natural gas storage contracts (1)

     86,726      (1,558 )     85,168               

Hattiesburg natural gas storage contracts (1)

     13,773      (501 )     13,272               

San Juan Basin water rights (1)

     750      (6 )     744               
    

  


 

              

Segment total

     434,150      (8,344 )     425,806               
    

  


 

              

NGL Pipelines & Services:

                                    

Shell natural gas processing agreement

     206,216      (45,110 )     161,106    $ (34,063 )   $ 172,153

Toca-Western natural gas processing contracts

     11,187      (1,444 )     9,743      (885 )     10,302

Toca-Western NGL fractionation contracts

     20,042      (2,589 )     17,453      (1,587 )     18,455

Mont Belvieu Storage II contracts

     8,127      (697 )     7,430      (464 )     7,663

Venice contracts

     6,635      (601 )     6,034      (136 )     6,499

STMA customer relationships (1)

     37,802      (1,308 )     36,494               

NGL Business customer relationships (1)

     32,800      (829 )     31,971               

Markham NGL storage contracts (1)

     32,664      (1,088 )     31,576               

Morgan’s Point (2)

     1,652              1,652               
    

  


 

  


 

Segment total

     357,125      (53,666 )     303,459      (37,135 )     215,072
    

  


 

  


 

Petrochemical Services:

                                    

Mont Belvieu Splitter III contracts

     53,000      (4,417 )     48,583      (2,902 )     50,098

BEF UOP License Fee

     1,097      (109 )     988      (24 )     1,633

Port Neches pipeline contracts

     2,400      (682 )     1,718      (310 )     2,090
    

  


 

  


 

Segment total

     56,497      (5,208 )     51,289      (3,236 )     53,821
    

  


 

  


 

Total all segments

   $ 1,054,784    $ (74,183 )   $ 980,601    $ (40,371 )   $ 268,893
    

  


 

  


 


(1) These intangible assets were acquired as a result of the GulfTerra Merger and the South Texas midstream assets in September 2004. These amounts are based on our preliminary purchase price allocation for the GulfTerra Merger (see Note 4), which is subject to change.
(2) These intangible assets were acquired in December 2004 in connection with our acquisition of the Morgan’s Point assets. The amounts assigned to intangible assets are based upon our preliminary allocation of the acquisition purchase price, which is subject to change.

 

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Table of Contents
Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

As of December 31, 2004, our primary intangible assets were as follows:

 

    GulfTerra and STMA customer relationships . These intangible assets represent the customer base that GulfTerra and the South Texas midstream assets serve through providing services, including natural gas gathering and processing, NGL fractionation and pipeline transportation. These entities conduct the majority of their business through the use of written contracts; thus, the customer relationships represent the rights we own arising from those contractual agreements. We amortize the customer relationship values using a method that closely resembles the pattern in which the economic benefits of the underlying oil and natural gas resource bases from which the customers produce are consumed or otherwise used. This group of intangible assets consists of our (i) Offshore Pipelines & Platforms customer relationships; (ii) San Juan Gathering System customer relationships; (iii) Permian Basin customer relationships; (iv) STMA customer relationships and (v) NGL Business customer relationships.

 

    GulfTerra storage contracts . These intangible assets represent the contracts that GulfTerra entered into to provide for the storage of natural gas or NGLs for various customers at its Petal and Hattiesburg natural gas or Markham NGL storage facilities. These contracts are amortized on a straight-line basis over the remainder of their respective contract terms, which we estimate range from 2 to 18 years. This group of intangible assets consists of our (i) Petal natural gas storage contracts; (ii) Hattiesburg natural gas storage contracts and (iii) Markham NGL storage contracts.

 

    Shell natural gas processing agreement . We acquired this intangible asset in connection with our acquisition of certain midstream energy assets from Shell located along the Gulf Coast in 1999. The value of the Shell agreement is being amortized on a straight-line basis over the remainder of its initial 20-year contract term through 2019. For additional information regarding our related party relationship with Shell, see Note 13.

 

    Mont Belvieu storage and propylene fractionation contracts . We acquired these storage and propylene fractionation contracts during 2002 in connection with our purchase of certain midstream energy assets from Diamond-Koch that were located in Mont Belvieu, Texas. The values of these contracts are being amortized on a straight-line basis over the 35-year remaining economic life of the assets to which they relate. This group of intangible assets consists of our Mont Belvieu Storage II contracts and Mont Belvieu Splitter III contracts.

 

    Toca-Western contracts . We acquired these natural gas processing and NGL fractionation contracts during 2002 in connection with our purchase of certain midstream energy assets from Toca-Western. The Toca-Western natural gas processing contracts are being amortized on a straight-line basis over the expected 20-year economic life of the natural gas supplies supporting these contracts. The value of the Toca-Western NGL fractionation contracts is being amortized on a straight-line basis over the expected 20-year remaining life of the assets to which they relate.

 

Our remaining intangible assets primarily represent the value of contracts rights we own under product handling and transportation agreements, processing license agreements and water rights. In general, the value of these contract rights are being amortized using the straight-line method over either the terms of underlying contracts or the remaining useful economic life of the assets to which they relate.

 

Goodwill. In general, goodwill represents the excess of the purchase price of an acquired entity over the amounts assigned to assets acquired (including identifiable intangible assets) and liabilities assumed. Goodwill is not amortized; however, it is subject to annual impairment testing. Our preliminary estimate of goodwill associated with the GulfTerra Merger is $376.8 million, which we allocated between our new business segments in proportion to the tangible and intangible assets we recorded for this transaction in purchase accounting. The

 

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ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

“GulfTerra Merger” goodwill is associated with our view of the future results from GulfTerra’s operations, based on the strategic location of GulfTerra’s assets as well as their industry relationships. Based on miles of pipelines, GulfTerra is one of the largest natural gas gathering and transportation companies providing services to producers in the natural gas supply regions of the central and western Gulf of Mexico and onshore in Texas and New Mexico. These regions, especially the deepwater regions of the Gulf of Mexico, offer us significant growth potential through the acquisition and construction of additional pipelines, platforms, processing and storage facilities and other midstream energy infrastructure. Since we have not finalized our allocation of the purchase price associated with the GulfTerra Merger, our estimate of goodwill related to this transaction is preliminary (see Note 4). The remainder of our goodwill amounts are associated with prior acquisitions, principally that of our purchase of propylene fractionation assets from Diamond-Koch in February 2002.

 

The following table summarizes our goodwill amounts at the dates indicated:

 

     At December 31,

     2004

   2003

Offshore Pipelines & Services

             

GulfTerra Merger

   $ 62,348       

Onshore Natural Gas Pipelines & Services

             

GulfTerra Merger

     290,397       

NGL Pipelines & Services

             

GulfTerra Merger

     24,026       

Acquisition of interest in Mont Belvieu NGL fractionator

     7,857    $ 7,857

Acquisition of interest in Wilprise

     880      880

Petrochemical Services

             

Acquisition of Mont Belvieu propylene fractionation assets

     73,690      73,690
    

  

Totals

   $ 459,198    $ 82,427
    

  

 

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

 

     For Year Ended December 31,

     2004

   2003

   2002

Offshore Pipelines & Services

   $ 6,965              

Onshore Natural Gas Pipelines & Services

     8,344              

NGL Pipelines & Services

     16,531    $ 12,977    $ 12,197

Petrochemical Services

     1,973      1,848      1,388
    

  

  

Total all segments

   $ 33,813    $ 14,825    $ 13,585
    

  

  

 

For 2005, amortization expense attributable to these intangible assets is currently estimated at $86.5 million. Based on information currently available, we estimate that amortization expense related to existing intangible assets could approximate $80.2 million during 2006, $75.1 million during 2007, $70.5 million during 2008 and $65.9 million during 2009.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

9. DEBT OBLIGATIONS

 

Our debt consisted of the following at the dates indicated:

 

     December 31,

 
     2004

    2003

 

Operating Partnership debt obligations:

                

Interim Term Loan, variable rate, repaid in May 2004 (1)

           $ 225,000  

364-Day Revolving Credit Facility, variable rate, terminated in September 2004 (2)

             70,000  

Multi-Year Revolving Credit Facility, variable rate, terminated in September 2004 (2)

             115,000  

364-Day Acquisition Credit Facility, variable rate, repaid in
February 2005 (3,4)

   $ 242,229          

Multi-Year Revolving Credit Facility, variable rate, due
September 2009 (2,4)

     321,000          

Seminole Notes, 6.67% fixed-rate, $15 million due in December 2005 (5)

     15,000       30,000  

MBFC Loan, 8.70% fixed-rate, due March 2010

     54,000       54,000  

Senior Notes A, 8.25% fixed-rate, repaid March 2005

     350,000       350,000  

Senior Notes B, 7.50% fixed-rate, due February 2011

     450,000       450,000  

Senior Notes C, 6.375% fixed-rate, due February 2013

     350,000       350,000  

Senior Notes D, 6.875% fixed-rate, due March 2033

     500,000       500,000  

Senior Notes E, 4.00% fixed-rate, due October 2007

     500,000          

Senior Notes F, 4.625% fixed-rate, due October 2009

     500,000          

Senior Notes G, 5.60% fixed-rate, due October 2014

     650,000          

Senior Notes H, 6.65% fixed-rate, due October 2034

     350,000          

GulfTerra debt obligations: (5)

                

Senior Notes, 6.25% fixed-rate, due June 2010 (6)

     750          

Senior Subordinated Notes, 8.50% fixed-rate, due June 2010

     3,858          

Senior Subordinated Notes, 8.50% fixed-rate, due June 2011

     1,777          

Senior Subordinated Notes, 10.625% fixed-rate, due December 2012

     84          

EPGP related party obligation:

                

$370 Million Note, 6.25% fixed-rate, final installment due November 2019

     366,433          
    


 


Total principal amount

     4,655,131       2,144,000  

Net unamortized discounts

     (9,239 )     (5,983 )

Other

     1,777       1,531  
    


 


Subtotal long-term debt

     4,647,669       2,139,548  

Less current maturities of debt (7)

     (18,450 )     (240,000 )
    


 


Long-term debt

   $ 4,629,219     $ 1,899,548  
    


 


Standby letters of credit outstanding (8)

   $ 139,052     $ 1,300  
    


 



(1) We used the proceeds from EPD’s May 2004 common unit offering to fully repay and terminate the Interim Term Loan.
(2) These facilities were terminated on September 30, 2004, and replaced by a new Multi-Year Revolving Credit Facility having $750 million of borrowing capacity due September 2009.
(3) We used the proceeds from EPD’s February 2005 common unit offering to fully repay and terminate the 364-Day Acquisition Credit Facility.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

(4) These facilities became effective concurrently with the closing of the GulfTerra Merger on September 30, 2004. The new $750 million Multi-Year Revolving Credit Facility replaced the $230 million 364-Day Revolving Credit Facility and the $270 million then existing Multi-Year Revolving Credit Facility. The $750 million borrowing capacity is reduced by the amount of standby letters of credit outstanding.
(5) Solely as it relates to the assets of our GulfTerra and Seminole subsidiaries, our senior indebtedness is structurally subordinated and rank junior in right of payment to indebtedness of GulfTerra and Seminole.
(6) Remaining notes outstanding were called and retired in February 2005.
(7) In accordance with SFAS No. 6, “ Classification of Short-Term Obligations Expected to Be Refinanced ,” long-term and current maturities of debt at December 31, 2004 reflected (i) our refinancing of Senior Notes A with proceeds from our Senior Notes I and J in March 2005 and (ii) the repayment of our 364-Day Acquisition Credit Facility using proceeds from EPD’s equity offering completed in February 2005. Our classification of current maturities of debt at December 31, 2003 reflected our option and ability to convert any revolving credit balance outstanding at maturity under the 364-Day Revolving Credit Facility to a one-year term loan (which would have been due October 2005) in accordance with the terms of the agreement.
(8) Of the $139 million standby letters of credit outstanding at December 31, 2004, $24 million were issued under our Multi-Year Revolving Credit Facility, and the remaining $115 million is associated with a letter of credit facility we entered into in November 2004 in connection with our Independence Hub capital project.

 

General description of consolidated debt

 

The following is a summary of the significant aspects of our debt obligations at December 31, 2004:

 

Parent-Subsidiary guarantor relationships. Through guarantor agreements which are nonrecourse to us, EPD acts as guarantor of the debt obligations of its Operating Partnership, with the exception of the Seminole Notes and the senior and senior subordinated notes of GulfTerra. If the Operating Partnership were to default on any debt EPD guarantees, EPD would be responsible for full repayment of that obligation. The Seminole Notes are unsecured obligations of Seminole Pipeline Company (of which we own an effective 86.6% of its capital stock). The senior and senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).

 

GulfTerra’s Senior Subordinated and Senior Notes. As a result of completing the GulfTerra Merger on September 30, 2004, EPD recorded in consolidation GulfTerra’s $921.5 million of outstanding senior and senior subordinated notes. Of this amount, $915 million was purchased on October 5, 2004 by the Operating Partnership pursuant to its tender offers. The note holders also approved amendments in connection with accepting the tender offers that removed all restrictive covenants governing the notes. For additional information regarding the tender offers, please read “ —364-Day Acquisition Credit Facility—Tender offers for GulfTerra senior and senior subordinated notes ” within this general description of debt. In February 2005, EPD redeemed, at a premium, the remaining $0.8 million outstanding under GulfTerra’s 6.25% senior notes due June 2010.

 

$370 Million Note Payable . On September 30, 2004, we borrowed $370 million from DDC, which owns a 4.5% membership interest in the Company. We used the proceeds from this borrowing to fund the cash portion of the consideration paid to El Paso for a 50% membership interest in GulfTerra GP (see Note 4). This promissory note bears a fixed-interest rate of 6.25%. Installment payments of $6.6 million are due quarterly from November 2004 through November 2019. Under terms of the note agreement, we are allowed to defer up to $13.2 million of scheduled quarterly installment payments at any time, except that all principal and accrued interest must be repaid by the November 2019 maturity date.

 

364-Day Acquisition Credit Facility. In August 2004, the Operating Partnership entered into a new 364-day credit agreement. The $2.25 billion Acquisition Credit Facility was an unsecured 364-day facility that was used

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

to provide interim financing for certain transactions associated with the GulfTerra Merger, the refinancing of GulfTerra’s existing secured credit facility and term loans and the purchase of GulfTerra’s senior and senior subordinated notes in connection with the Operating Partnership’s tender offers for those notes. This facility became effective concurrent with the closing of the GulfTerra Merger and was to mature on September 29, 2005. In February 2005, we fully repaid and terminated the 364-Day Acquisition Credit Facility using proceeds received from EPD’s February 2005 common unit offering. See Note 20 for additional information regarding EPD’s February 2005 common unit offering.

 

As defined by the credit agreement, variable interest rates charged under this facility generally bore interest, at our election at the time of each borrowing, at (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus ½% or (2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate.

 

This credit agreement provided for the mandatory prepayment of loans and termination of commitments equal to the proceeds from and upon the consummation of any public or private debt or equity offerings by EPD on or after August 15, 2004, excluding equity issued with respect to EPD’s distribution reinvestment plan, employee unit purchase plan and the exercise of any outstanding options with respect to EPD’s common units. With the completion of the Operating Partnership’s private offering of senior notes on October 4, 2004, we repaid approximately $2 billion borrowed under this facility, which reduced our borrowing capacity under this facility by an equal amount.

 

This revolving credit agreement contained various covenants related to our ability to incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; and make certain investments. The loan agreement also required the Operating Partnership to satisfy certain financial covenants at the end of each fiscal quarter. The Operating Partnership is in compliance with these covenants at December 31, 2004.

 

Tender offers for GulfTerra senior and senior subordinated notes

 

On August 4, 2004, in anticipation of completing the GulfTerra Merger, the Operating Partnership commenced four cash tender offers to purchase any and all of the outstanding senior and senior subordinated notes of GulfTerra having a total outstanding principal amount of approximately $921.5 million. In connection with the tender offers, GulfTerra executed supplements to the indentures governing these notes that eliminated certain restrictive covenants and default provisions contained in those indentures upon our purchase of more than a majority in principal amount of each series of the outstanding senior and senior subordinated notes.

 

Substantially all of the GulfTerra notes ($915 million of $921.5 million) were tendered pursuant to the tender offers. On September 30, 2004, the Operating Partnership borrowed $1.1 billion under its 364-Day Acquisition Credit Facility in anticipation of completing the tender offers and placed these funds in escrow. On October 5, 2004, the Operating Partnership purchased the notes for a total price of approximately $1.1 billion, which included $27 million related to consent payments.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table shows the four GulfTerra senior debt obligations affected, including the principal amount of each series of notes tendered, as well as the payment made by the Operating Partnership to complete the tender offers.

 

Description


  

Principal

Amount

Tendered


  

Cash payments made by the

Operating Partnership


     

Accrued

Interest


  

Tender

Price (1)


  

Total

Paid


8.50% Senior Subordinated Notes due 2010

                           

(Represents 98.2% of principal amount outstanding)

   $ 212,057    $ 6,209    $ 246,366    $ 252,575

10.625% Senior Subordinated Notes due 2012

                           

(Represents 99.9% of principal amount outstanding)

     133,916      4,901      167,612      172,513

8.50% Senior Subordinated Notes due 2011

                           

(Represents 99.5% of principal amount outstanding)

     319,823      9,364      359,379      368,743

6.25% Senior Notes due 2010

                           

(Represents 99.7% of principal amount outstanding)

     249,250      5,366      274,073      279,439
    

  

  

  

Totals

   $ 915,046    $ 25,840    $ 1,047,430    $ 1,073,270
    

  

  

  


(1) Tender price includes consent payment of $30 per $1,000 principal amount tendered.

 

Multi-Year Revolving Credit Facility. In August 2004, the Operating Partnership entered into a five-year $750 million revolving credit agreement that includes a sublimit of $100 million for standby letters of credit. This facility became effective concurrent with the closing of the GulfTerra Merger and will mature on September 30, 2009. This facility replaced the Operating Partnership’s then existing $270 million Multi-Year Revolving Credit Facility and $230 million 364-Day Revolving Credit Facility, which were terminated upon the effective date of the new facility. The Operating Partnership’s borrowings under this agreement are unsecured general obligations that are non-recourse to us. EPD has guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.

 

As defined by the credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at (1) the greater of (a) the Prime Rate or (b) the Federal Funds Effective Rate plus  1 / 2 % or (2) a Eurodollar rate plus an applicable margin or (3) a Competitive Bid Rate. This revolving credit agreement contains various covenants similar to those of the Operating Partnership’s 364-Day Acquisition Credit Facility. The Operating Partnership is in compliance with these covenants at December 31, 2004.

 

Senior Notes A, B, C and D . These fixed-rate notes are an unsecured obligation of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. They are senior to any future subordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to us. EPD has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes are subject to make-whole redemption rights and were issued under an indenture containing certain covenants. These covenants restrict the Operating Partnership’s ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. The Operating Partnership was in compliance with these covenants at December 31, 2004. On March 15, 2005, the Operating Partnership repaid the $350 million in indebtedness outstanding under Senior Notes A using the proceeds received from EPD’s February 2005 private offering of senior notes. See Note 20 for information regarding this subsequent event.

 

Senior Notes E, F, G and H. On September 23, 2004, the Operating Partnership priced a private offering of an aggregate of $2 billion in principal amount of senior unsecured notes in a transaction exempt from the

 

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Index to Financial Statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

registration requirements under the Securities Act of 1933, as amended. On October 4, 2004, these notes were issued. The interest rate, principal amount and net proceeds, before expenses, for each senior note in this offering are shown in the following table:

 

Senior Note Issued


   Fixed
Interest
Rate


    Principal
Amount


   Bond
Discount


   Proceeds to
Us, Before
Expenses


Senior Notes E, due October 2007

   4.000 %   $ 500,000    $ 2,140    $ 497,860

Senior Notes F, due October 2009

   4.625 %     500,000      4,405      495,595

Senior Notes G, due October 2014

   5.600 %     650,000      4,784      645,216

Senior Notes H, due October 2034

   6.650 %     350,000      4,203      345,797
          

  

  

Totals

         $ 2,000,000    $ 15,532    $ 1,984,468
          

  

  

 

The net proceeds from this offering were used to reduce debt amounts outstanding under the Operating Partnership’s $2.25 billion 364-Day Acquisition Credit Facility that was used to partially fund the GulfTerra Merger on September 30, 2004.

 

These fixed-rate notes are unsecured obligations of the Operating Partnership and rank equally with its existing and future unsecured and unsubordinated indebtedness. The Operating Partnership’s borrowings under these notes are non-recourse to us. EPD has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. These notes were issued under an indenture containing certain covenants, which restrict the Operating Partnership’s ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions. The Operating Partnership is in compliance with these covenants at December 31, 2004.

 

On January 24, 2005, the Operating Partnership filed a registration statement for an offer to exchange these notes for registered debt securities with identical terms.

 

Senior Notes Offering. On February 15, 2005, the Operating Partnership sold $500 million in principal amount of senior notes in a private offering. See Note 20 for information regarding this subsequent event.

 

Pascagoula MBFC Loan . In connection with the construction of our Pascagoula, Mississippi natural gas processing plant, the Operating Partnership entered into a ten-year fixed-rate loan with the Mississippi Business Finance Corporation (“MBFC”). This loan is subject to a make-whole redemption right and is guaranteed by EPD through an unsecured and unsubordinated guarantee. The Pascagoula MBFC Loan contains certain covenants including the maintenance of appropriate levels of insurance on the Pascagoula facility. We were in compliance with the covenants at December 31, 2004.

 

The indenture agreement for this loan contains an acceleration clause whereby if our credit rating by Moody’s declines below Baa3 in combination with our credit rating at Standard & Poor’s remaining at BB+ or below, the $54 million principal balance of this loan, together with all accrued and unpaid interest would become immediately due and payable 120 days following such event. If such an event occurred, we would have to either redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to support our obligation under this loan.

 

Petal Industrial Development Revenue Bonds . In April 2004, Petal Gas Storage L.L.C. (“Petal”), a wholly owned subsidiary of GulfTerra, borrowed $52 million from the MBFC pursuant to a loan agreement between Petal and the MBFC. On the same date, the MBFC issued $52 million in Industrial Development Revenue Bonds to another wholly owned subsidiary of GulfTerra. The loan agreement and the Industrial Development Revenue

 

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ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Bonds have identical fixed interest rates of 6.25% and maturities of fifteen years. The bonds and the associated tax exemptions are authorized under the Mississippi Business Finance Act. Petal may repay the loan agreement without penalty, and thus cause the Industrial Development Revenue Bonds to be redeemed, any time after one year from their date of issue. We have netted the loan amount and the bond amount of $52 million and the interest payable and interest receivable amount of $2.2 million on our Consolidated Balance Sheet as of December 31, 2004. Beginning in the fourth quarter of 2004, we also netted the interest expense and interest income amounts of $0.8 million attributable to these instruments on our Statements of Consolidated Operations and Comprehensive Income. Our presentation of the Petal Industrial Development Revenue Bonds is reflected in accordance with the provisions of FIN No. 39, “ Offsetting of Amounts Related to Certain Contracts ”, and SFAS No. 140, “ Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities ”, since we have the ability and intent to offset these items.

 

Loss due to write-off of unamortized debt issuance costs . As a result of terminating our 364-Day Revolving Credit Facility and our previous Multi-Year Revolving Credit Facility on September 30, 2004, we expensed $0.7 million of unamortized debt issuance costs.

 

Information regarding variable interest rates paid

 

The following table shows the range of interest rates paid and weighted-average interest rate paid on our variable-rate debt obligations during 2004.

 

    

Range of
interest rates

paid


   Weighted-
average
interest rate
paid


Interim Term Loan (terminated May 2004)

   1.72% to 1.78%    1.76%

364-Day Revolving Credit Facility (terminated September 30, 2004)

   1.72% to 4.00%    1.82%

Multi-Year Revolving Credit Facility (terminated September 30, 2004)

   1.67% to 4.25%    1.83%

364-Day Acquisition Credit Facility (effective September 30, 2004)

   2.67% to 4.75%    3.50%

Multi-Year Revolving Credit Facility (effective September 30, 2004)

   2.64% to 5.25%    3.06%

 

Consolidated debt maturity table

 

The following table shows scheduled maturities of the principal amounts of our debt obligations for the next 5 years and in total thereafter.

 

2005

   $ 18,450

2006

     3,802

2007

     504,045

2008

     4,242

2009

     825,576

Thereafter

     3,299,016
    

Total scheduled principal to be repaid

   $ 4,655,131
    

 

In accordance with SFAS No. 6, “ Classification of Short-Term Obligations Expected to Be Refinanced ”, the amount shown in the table above for 2005 excludes the $242.2 million principal amount due under our 364-Day Acquisition Credit Facility at December 31, 2004. We refinanced this short-term obligation using proceeds from EPD’s equity offering completed in February 2005. As a result, we have reclassified this amount to long-term debt and shown it as a component of principal amounts due after 2009.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

In addition, the long-term portion of our debt obligations at December 31, 2004 reflects our refinancing of the $350 million in principal amount Senior Notes A (due March 2005) with proceeds from the Operating Partnership’s March 2005 issuance of $250 million in principal amount Senior Notes I (due March 2015) and the Operating Partnership’s $250 million in principal amount Senior Notes J (due March 2035). In accordance with SFAS No. 6, the principal amount due under Senior Notes A has been reclassified to amounts due after 2009 to match the scheduled maturities of Senior Notes I and J.

 

Joint venture debt obligations

 

We have ownership interests in four joint ventures having long-term debt obligations. The following table shows (i) our ownership interest in each entity at December 31, 2004, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate at December 31, 2004, on a 100% basis to the joint venture and (iii) the corresponding scheduled maturities of such long-term debt.

 

    

Our

Ownership

Interest


    Total

   Scheduled Maturities of Long-Term Debt

          2005

   2006

   2007

   2008

   2009

   After
2009


Cameron Highway (1)

   50.0 %   $ 297,000           $ 8,125    $ 32,500    $ 164,375    $ 16,000    $ 76,000

Deepwater Gateway

   50.0 %     144,000    $ 22,000      22,000      22,000      22,000      56,000       

Poseidon

   36.0 %     107,000                           107,000              

Evangeline

   49.5 %     35,650      5,000      5,000      5,000      5,000      5,000      10,650
          

  

  

  

  

  

  

Total

         $ 583,650    $ 27,000    $ 35,125    $ 59,500    $ 298,375    $ 77,000    $ 86,650
          

  

  

  

  

  

  


(1) The scheduled maturities for Cameron Highway assume that the construction loan is or will be converted into a term loan in July 2005 and scheduled repayments will begin on December 31, 2006.

 

The following is a summary of the significant aspects of the debt obligations of our unconsolidated affiliates.

 

Cameron Highway . In July 2003, Cameron Highway entered into a $325 million project loan facility, consisting of a $225 million construction loan and $100 million of senior secured notes, to finance a substantial portion of the cost to construct the Cameron Highway oil pipeline.

 

The construction loan bears interest at a variable rate. Once the Cameron Highway oil pipeline has commenced operations and transported a certain level of volumes (as specified in the credit agreement), the construction loan will convert to a term loan maturing in July 2008, subject to the terms of the loan agreement. At the end of the first quarter following the first anniversary of the conversion into a term loan, Cameron Highway will be required to make quarterly principal payments of $8.1 million, with the remaining unpaid principal amount payable on the maturity date. If the construction loan fails to convert into a term loan by January 2006, the construction loan and senior secured notes become fully due and payable. At December 31, 2004, Cameron Highway had $197 million outstanding under its construction loan at an average interest rate of 5.48%.

 

The interest rate on Cameron Highway’s senior secured notes is 3.25% over the rate on 10-year U.S. Treasury securities. Principal payments of $4 million are due quarterly from September 2008 through December 2011, $6 million each from March 2012 through December 2012, and $5 million each from March 2013 through the principal maturity date of December 2013. At December 31, 2004, Cameron Highway had $100 million outstanding under its senior secured notes at an average interest rate of 7.36%.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The project loan facility as a whole is secured by (1) substantially all of Cameron Highway’s assets, including, upon conversion to a term loan, a debt service reserve capital account, and (2) all of the equity interest in Cameron Highway. Other than the pledge of our equity interest and our construction obligations under the relevant producer agreements, the debt is non-recourse to us. The construction loan and senior secured notes prohibit Cameron Highway from making distributions to us until the construction loan is converted into a term loan and Cameron Highway meets certain financial requirements.

 

Deepwater Gateway . In August 2002, Deepwater Gateway, our unconsolidated affiliate which owns the Marco Polo tension-leg platform, obtained a $155 million project finance loan to finance a substantial portion of the cost to construct the Marco Polo tension-leg platform and related facilities. Construction of the Marco Polo tension-leg platform was completed during the first quarter of 2004, and in June 2004, Deepwater Gateway converted the project finance loan into a term loan which matures in June 2009. The term loan is payable in twenty equal quarterly installments of $5.5 million each (which began on September 30, 2004), and the remaining outstanding principal of $45 million is due on the maturity date. Interest rates are variable and the loan is collateralized by substantially all of Deepwater Gateway’s assets. Deepwater Gateway is required to maintain a debt service reserve of not less than the projected principal, interest and fees due on the term loan for the immediately succeeding six month period. If Deepwater Gateway defaults on its payment obligations under the term loan, we would be required to pay the lenders all distributions we or any of our subsidiaries had received from Deepwater Gateway up to $22.5 million. As of December 31, 2004, the average interest rate charged under this term loan was 4.42%.

 

Poseidon . Poseidon is party to a $170 million revolving credit facility which matures in January 2008. The interest rates Poseidon is charged on balances outstanding under its revolving credit facility are variable and depend on its ratio of total debt to earnings before interest, taxes, depreciation and amortization. This credit agreement is secured by substantially all of Poseidon’s assets. As of December 31, 2004, the average interest rate charged under Poseidon’s revolving credit facility was 4.58%.

 

Evangeline . At December 31, 2004, long-term debt for Evangeline consisted of (i) $28.2 million in principal amount of 9.9% fixed-rate Series B senior secured notes that are due in December 2010 and (ii) a $7.5 million subordinated note payable. The Series B senior secured notes are collateralized by Evangeline’s property, plant and equipment; proceeds from a gas sales contract; and by a debt service 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 incurred the subordinated note payable in connection with its acquisition of a contract-based intangible asset in the early 1990s. This 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. In general, interest accrues on the subordinated note at a variable-rate based on LIBOR plus ½%. The variable interest rate paid on this debt at December 31, 2004 was 1.73%.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

10. MINORITY INTEREST

 

Minority interest represents third-party and related party ownership interests in the net assets of certain of our subsidiaries. The following table shows the components of minority interest at the dates indicated:

 

     December 31,

     2004

   2003

EPD’s limited partners:

             

Non-affiliates of EPGP Members

   $ 3,992,153    $ 1,244,018

Affiliates of EPGP Members

     802,505      422,596

Joint venture partners

     71,040      86,356
    

  

     $ 4,865,698    $ 1,752,970
    

  

 

The minority interest attributable to EPD’s limited partners consists of EPD common units held by the public, Shell, El Paso and affiliates of the Company, which primarily includes EPCO, and is net of unamortized deferred compensation of $10.9 million which represents the value of EPD common units issued to key employees of EPCO. The minority interest attributable to joint venture partners as of December 31, 2004, is primarily attributable to our partners in Tri-States, Seminole, Wilprise, Independence Hub and the Mid-America pipeline system. The minority interest attributable to joint venture partners as of December 31, 2003, is primarily attributable to our partners in Seminole, Wilprise and the Mid-America pipeline system. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third-party investor’s ownership in our consolidated balance sheet amounts shown as minority interest.

 

The following table shows distributions paid to and contributions from minority interests attributable to each component of minority interest for the periods indicated:

 

     For Year Ended December 31,

     2004

   2003

   2002

Distributions paid to minority interests:

                    

EPD’s limited partners

   $ 398,247    $ 287,387    $ 203,013

Joint venture partners

     6,440      4,964      1,018
    

  

  

     $ 404,687    $ 292,351    $ 204,031
    

  

  

Contributions from minority interests:

                    

EPD’s limited partners

   $ 828,956    $ 667,945    $ 178,859

Joint venture partners

     9,585             1
    

  

  

     $ 838,541    $ 667,945    $ 178,860
    

  

  

 

Distributions paid to EPD’s limited partners primarily represent the quarterly cash distributions paid by EPD in accordance with their Limited Partnership Agreement. Contributions from EPD’s limited partners primarily represent proceeds received from EPD common unit offerings.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

11. CAPITAL STRUCTURE

 

At the dates indicated, our members’ equity account balances and ownership interests were as follows:

 

     Membership
Percentage at
December 31,
2004


    Members’ Equity Account
At December 31,


               2004        

           2003        

DFI

   85.595 %   $ 46,104    $ 28,830

DDC

   4.505 %     3,380      2,623

El Paso

   9.900 %     90,845       
          

  

Subtotal

           140,329      31,453
          

  

Accumulated Other Comprehensive Income

           24,554      4,990
          

  

Total

         $ 164,883    $ 36,443
          

  

 

Earnings and cash distributions are allocated to Member capital accounts in accordance with their respective membership percentages. DFI acquired Shell’s 30% member interest in us on September 12, 2003. On September 30, 2004, El Paso was granted a 9.9% membership interest in the Company in connection with our acquisition of El Paso’s 50% membership interest in GulfTerra GP (see Note 4). In January 2005, an affiliate of EPCO purchased El Paso’s 9.9% membership interest in us (see Note 20). See Note 17 for information regarding our Accumulated Other Comprehensive Income.

 

During 2004, DFI made a $2.9 million non-cash contribution in order to fund various administrative expenses of the Company.

 

12. PROVISION FOR INCOME TAXES FOR CERTAIN PIPELINE OPERATIONS

 

Our provision for income taxes is limited to certain income-based state franchise tax obligations of our Mid-America and Seminole pipelines and federal tax obligations of our Seminole pipeline (both pipeline systems were acquired in 2002). One of our subsidiaries, which owns the Seminole pipeline, is a corporation and substantially our only consolidated entity subject to federal income taxes. The following table summarizes our provision for income taxes for the periods indicated:

 

     For Year Ended December 31,

 
     2004

   2003

   2002

 

Current:

                      

Federal tax benefit

                 $ (391 )

State tax expense (benefit)

   $ 157    $ 47      (55 )
    

  

  


Total current

     157      47      (446 )
    

  

  


Deferred:

                      

Federal

     1,620      4,556      1,812  

State

     1,984      690      268  
    

  

  


Total deferred

     3,604      5,246      2,080  
    

  

  


Provision for income taxes

   $ 3,761    $ 5,293    $ 1,634  
    

  

  


 

Net deferred tax assets primarily relate to federal tax net operating loss carryovers and differences in the book and tax basis of property, plant and equipment. The federal tax net operating loss carryovers are projected

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

to be utilized within the 20 year carryover period. A valuation allowance of $0.1 million was recorded in 2004 against the benefit of both the current year and all prior year state tax net operating losses. The state net operating loss carryovers are not expected to be utilized within the 5 year carryover period and will expire over the next 3 to 5 years.

 

13. RELATED PARTY TRANSACTIONS

 

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

 

     For Year Ended December 31,

     2004

   2003

   2002

Revenues from consolidated operations

                    

EPCO and subsidiaries

   $ 2,697    $ 4,241    $ 3,630

Shell

     542,912      293,109      282,820

Unconsolidated affiliates

     258,541      266,894      196,267
    

  

  

Total

   $ 804,150    $ 564,244    $ 482,717
    

  

  

Operating costs and expenses

                    

EPCO and subsidiaries

   $ 202,561    $ 149,626    $ 103,210

Shell

     725,420      607,277      531,712

Unconsolidated affiliates

     37,587      43,752      60,657
    

  

  

Total

   $ 965,568    $ 800,655    $ 695,579
    

  

  

General and administrative expenses

                    

EPCO Administrative Services Agreement

   $ 27,454    $ 27,518    $ 24,204

Other EPCO transactions

     653      442      n/a
    

  

  

Total

   $ 28,107    $ 27,960    $ 24,204
    

  

  

Interest expense

                    

DDC

   $ 5,849      n/a      n/a

 

Relationship with EPCO

 

We have an extensive and ongoing relationship with EPCO. EPCO is controlled by Dan L. Duncan, who is one of our directors and Chairman. In addition, our executive and other officers are employees of EPCO, including Robert G. Phillips who is our Chief Executive Officer and one of our directors.

 

On September 30, 2004, we borrowed $370 million from DDC, which owns a 4.5% membership interest in the Company (see Note 4). DDC is wholly owned by Dan L. Duncan. We used the proceeds from this borrowing to fund the cash portion of the consideration paid to El Paso for a 50% membership interest in GulfTerra GP (see Note 4). During 2004, we incurred $5.8 million of interest in connection with the $370 million we borrowed from DDC on September 30, 2004.

 

Mr. Duncan owns 50.4% of the voting stock of EPCO. The remaining shares of EPCO capital stock are held primarily by trusts for the benefit of members of Mr. Duncan’s family. In addition, at December 31, 2004, EPCO and DDC, together, owned 90.1% of our membership interests. In January 2005, an affiliate of EPCO acquired El Paso’s 9.9% membership interest in us (see Note 20). As a result of this transaction, EPCO and its affiliates own 100% of our membership interests.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Our agreements with EPCO are not the result of arm’s-length transactions, and there can be no assurance that any of the transactions provided for therein are effected on terms at least as favorable to the parties to such agreement as could have been obtained from unaffiliated third parties.

 

Administrative Services Agreement . We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to the Administrative Services Agreement. Under the current terms of the Administrative Services Agreement, EPCO agrees to:

 

    employ the personnel necessary to manage our business and affairs;

 

    employ the operating personnel involved in our business;

 

    allow us to participate as named insureds in EPCO’s current insurance program with the costs being allocated among the parties on the basis set forth in the agreement;

 

    sublease to the Operating Partnership certain equipment which it holds pursuant to operating leases for one dollar per year and to assign to us its purchase option under such leases (the “retained leases”). EPCO remains liable for the cash lease payments associated with these assets.

 

The Operating Partnership records the lease payment made by EPCO as a non-cash operating expense (a component of operating costs and expenses as shown in our Statements of Consolidated Operations and Comprehensive Income) offset by a corresponding increase in its partners’ equity. As of December 31, 2004, the remaining retained leases were for a cogeneration unit and approximately 100 railcars. During 2004, the Operating Partnership exercised their options to purchase an isomerization unit and related equipment at a cost of $17.8 million. Should the Operating Partnership decide to exercise the purchase options associated with the remaining retained leases (which are also at fair value), an additional $2.3 million would be payable in 2008 and $3.1 million in 2016. In addition to retained lease expenses, operating costs and expenses include compensation charges for EPCO’s employees who operate our facilities.

 

General and administrative costs (as shown in our Statements of Consolidated Operations and Comprehensive Income) include the costs we pay EPCO for administrative support. Prior to January 1, 2004, our payments to EPCO and related non-cash expenses for administrative support were based on the following:

 

    We reimbursed EPCO for their share of the costs of certain of its employees in administrative positions that were active at the time of EPD’s initial public offering in July 1998 (the “pre-expansion” administrative personnel). Our obligation for reimbursing these costs was covered by the EPCO Administrative Service Fee. We paid $17.9 million and $16.6 million of such fees to EPCO during 2003 and 2002, respectively.

 

    To the extent that EPCO’s actual cost of providing the pre-expansion administrative personnel exceeded the Administrative Service Fee charged to us during a given year, we recorded a non-cash expense equal to the difference between EPCO’s actual cost and the Administrative Service Fee charged. The actual amounts incurred by EPCO for providing these services did not materially exceed the capped amount for the year ended December 31, 2002. For the year ended December 31, 2003, we recorded $0.4 million in non-cash expense related to this excess. The offset was recorded in partners’ equity as a general contribution to the Operating Partnership.

 

    We also reimbursed EPCO for all costs it incurs related to administrative personnel it hires in response to our expansion activities.

 

Effective January 1, 2004, the Administrative Services Agreement was amended to eliminate the fixed Administrative Services Fee and to provide that the Operating Partnership reimburse EPCO for all costs related to administrative support regardless of whether the costs are related to pre-expansion or expansion personnel who work on our behalf.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

On October 22, 2004, the Administrative Services Agreement was amended further to evidence our separateness from other persons and entities, to reflect a five-year license we granted for EPCO’s use of service marks owned by us and to provide for reimbursement of EPCO’s costs of discontinuing the use of those service marks over the term of the license. This amendment also provides that if EPCO and its affiliates are offered by a third party, or discover an opportunity to acquire from a third party, a business or assets that is or are in the same or similar line of business then being conducted by the Operating Partnership or in a line of business that would be a natural extension of any business then being conducted by the Operating Partnership (a “Business Opportunity”), EPCO shall promptly advise our Board of Directors of such Business Opportunity and offer such Business Opportunity to the Operating Partnership. If our Board of Directors does not advise EPCO within 10 days following the receipt of such notice that we wish to pursue such Business Opportunity, EPCO shall then be permitted to pursue such Business Opportunity. If our Board of Directors advises EPCO within such 10 day period that we want to pursue such Business Opportunity, EPCO shall not be permitted to pursue such Business Opportunity unless our Board of Directors subsequently advises EPCO that it has abandoned its pursuit of such Business Opportunity.

 

Other related party transactions with EPCO . The following is a summary of other significant related party transactions between EPCO and us, including those between EPCO and our unconsolidated affiliates.

 

    Prior to January 1, 2004, EPCO was the operator of our MTBE facility and Houston Ship Channel NGL import facility. During 2003 and 2002, we paid EPCO $0.8 million for such services. Such payments were terminated effective January 1, 2004 when the Operating Partnership assumed the role as operator of the facilities.

 

    We have entered into an agreement with an affiliate of EPCO to provide trucking services to us for the transportation of NGLs and other products.

 

    In the normal course of business, we also buy from and sell certain NGL products to an affiliate of EPCO.

 

We and EPD are separate legal entities from EPCO and its other affiliates, with assets and liabilities that are separate from EPCO and its other affiliates. EPCO primarily depends on the cash distributions it receives as an equity owner in EPD to fund its other operations and to meet its debt obligations. Our membership interests and the common units of EPD that are owned or controlled by EPCO and its affiliates, other than Dan Duncan LLC and the trusts affiliated with Dan L. Duncan, are pledged as security under an EPCO credit facility. In the event of a default under such credit facility, a change in control of Enterprise Products Partners or Enterprise Products GP could occur. For the years ended December 31, 2004, 2003 and 2002, EPCO received $173.7 million, $160.4 million and $146.6 million in quarterly cash distributions from EPD, respectively.

 

Relationship with Shell

 

We have a significant commercial relationship with Shell as a partner, customer and vendor. At March 15, 2005, Shell owned approximately 9.5% of EPD’s common units. In March 2005, EPD registered for resale Shell’s 36,572,122 common units under a registration rights agreement EPD executed with Shell in connection with EPD’s acquisition of certain of Shell’s Gulf Coast midstream energy businesses in September 1999. For additional information regarding this subsequent event, see Note 20. Shell sold its 30.0% interest in us to a subsidiary of EPCO in September 2003.

 

Shell is one of our largest customers. For the years ended December 31, 2004, 2003 and 2002, Shell accounted for 6.5%, 5.5% and 7.9%, respectively, of our consolidated revenues. Our revenues from Shell primarily reflect the sale of NGL and petrochemical products to Shell and the fees we charge Shell for natural

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

gas processing, pipeline transportation and NGL fractionation services. Our operating costs and expenses with Shell primarily reflect the payment of energy-related expenses related to the Shell natural gas processing agreement and the purchase of NGL products from Shell. We also lease from Shell its 45.4% interest in one of our propylene fractionation facilities located in Mont Belvieu, Texas.

 

The most significant contract affecting our natural gas processing business is the Shell margin-band/keepwhole processing agreement, which grants us the right to process Shell’s current and future production within state and federal waters of the Gulf of Mexico. The Shell processing agreement includes a life of lease dedication, which may extend the agreement well beyond its initial 20-year term ending in 2019.

 

We have also completed a number of business acquisitions and asset purchases involving Shell since 1999, including the acquisition of midstream energy assets located along the Gulf Coast for approximately $528.8 million in 1999; the purchase of the Lou-Tex Propylene pipeline for $100 million in 2000; and the acquisition of the Acadian Gas pipeline system in 2001 for $243.7 million.

 

Relationships with unconsolidated affiliates

 

Our investment in unconsolidated affiliates with industry partners is a vital component of our business strategy. These investments are a means by which we conduct our operations to align our interests with a supplier of raw materials or a consumer of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations. The following summarizes significant related party transactions we have with our current unconsolidated affiliates:

 

    We sell natural gas to Evangeline, which, in turn, uses the natural gas to satisfy supply commitments it has with a major Louisiana utility. For the years ended December 31, 2004, 2003 and 2002, revenues from Evangeline were $233.9 million, $212.7 million and $131.6 million, respectively. In addition, we have also furnished $11.1 million in letters of credit on behalf of Evangeline.

 

    We pay transportation fees to Dixie for propane movements on their system initiated by our NGL marketing activities. For the years ended December 31, 2004, 2003 and 2002, we paid Dixie $13.1 million, $11.3 million and $12.2 million, respectively, for such transportation fees.

 

    We pay Promix for the transportation, storage and fractionation of certain of our mixed NGL volumes. In addition, we sell natural gas to Promix for their fuel requirements. For the years ended December 31, 2004, 2003 and 2002, we paid Promix $23.2 million, $17.5 million and $18.4 million, respectively, for their services. Additionally, for the years ended December 31, 2004, 2003 and 2002, revenues from Promix for the purchase of natural gas were $18.6 million, $19.6 million and $12.7 million, respectively.

 

Prior to its becoming a consolidated subsidiary in March 2003, we paid EPIK for export services to load product cargoes for our NGL and petrochemical marketing customers. Also, prior to its becoming a consolidated subsidiary in September 2003, we sold high purity isobutane to BEF as a feedstock and purchased certain of BEF’s by-products. We also received transportation fees for BEF’s shipments of MTBE on our HSC pipeline and fractionation revenues for reprocessing mixed feedstock streams generated by BEF.

 

We enter into management agreements with some of our unconsolidated affiliates under which our unconsolidated affiliates pay us management fees for the operation and management of their assets. For the years ended December 31, 2004, 2003 and 2002, such fees approximated $2.1 million, $1.5 million and $1.4 million, respectively. Additionally, on occasion we pay for construction costs on behalf of our unconsolidated affiliates during the initial construction phase of their assets, and these amounts are settled by direct reimbursements for the amounts we are owed from our unconsolidated affiliates.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

14. UNIT OPTION PLAN ACCOUNTING

 

During 1998, EPCO adopted its 1998 Long-Term Incentive Plan (the “1998 Plan”). Under this program, non-qualified incentive options to purchase a fixed number of EPD common units may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. The exercise price per unit, vesting and expiration terms, and rights to receive distributions on units granted are determined by EPCO for each grant agreement. EPCO purchases common units to fund its obligations under the 1998 Plan at fair value either in the open market or from EPD (in the form of newly issued common units or reissued treasury units).

 

We account for our share of the costs of these awards using the intrinsic value-based method in accordance with APB No. 25, “ Accounting for Stock Issued to Employees .” The exercise price of each EPD option granted is equivalent to or greater than the market price of the unit at the date of grant. Accordingly, no compensation expense related to unit options has been recognized in our Statements of Consolidated Operations and Comprehensive Income for the periods presented. The option-related reimbursements (as described below) that we make to reimburse EPCO for its costs related to these awards are a component of “Cash distributions to minority interests” as shown in our Statements of Consolidated Cash Flows.

 

When employees exercise unit options, we reimburse EPCO for the difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units awarded to the employee. Effective January 1, 2004, with the amendment of the Administrative Services Agreement, we became responsible for reimbursing EPCO for all the costs it incurs when unit options are exercised. Under the amended agreement, our payment to EPCO is in the form of an option-related reimbursement regardless of how the option liability is satisfied (i.e., through open market purchases or units acquired from EPCO affiliates or EPD). During 2004 and 2003, we made $3.8 million and $2.7 million, respectively, in option-related reimbursements to EPCO to meet our obligations under EPCO’s 1998 Plan.

 

Prior to January 1, 2004, our responsibility for reimbursing EPCO for the cash outlay it incurred when these options were exercised was as follows:

 

    We reimbursed EPCO for the costs attributable to unit option awards granted to operations personnel it employed on our behalf.

 

    We reimbursed EPCO for the costs attributable to unit option awards granted to administrative and management personnel it hired in response to our expansion and business activities.

 

    We paid EPCO for our share of the costs attributable to unit option awards granted to certain of its employees in administrative and management positions that were active at the time of EPD’s initial public offering in July 1998 under one of two methods described as follows:

 

    if EPCO purchased common units in open market to fund its obligation to any employee of this group, the cost was reimbursed by us through the Administrative Service Fees we paid EPCO. EPCO was responsible for the actual cost of such award when the option was exercised. To the extent that EPCO’s total administrative expense incurred on our behalf (including the expense associated with equity-based awards satisfied through open market purchases) exceeded the annual Administrative Service Fee we paid to EPCO, such excess costs resulted in a non-cash charge to our earnings as a related-party expense. The offset was recorded in partners’ equity as a general contribution to the Operating Partnership; or

 

    if EPCO requested us to provide units to satisfy its obligations to these employees, we reimbursed EPCO for its actual costs of such awards.

 

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Index to Financial Statements

ENTERPRISE PRODUCTS GP, LLC

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

On July 1, 2005, we will adopt the provisions of SFAS No. 123(R), “Share-Based Payment.” This accounting guidance, which is applicable for the first interim or annual reporting period beginning after June 15, 2005, replaces SFAS No. 123, “ Accounting for Stock-Based Compensation ” and supersedes APB No. 25, “ Accounting for Stock Issued to Employees .” For additional information regarding this recent accounting standard, see Note 2.

 

Summary of 1998 Plan activity

 

The information in the following table shows unit option activity for EPCO personnel who work on our behalf:

 

     Number of
Units


    Weighted-
average strike
price


Outstanding at January 1, 2002

   2,201,640     $ 11.88

Granted

   379,000       23.42

Exercised

   (270,562 )     4.98
    

 

Outstanding at December 31, 2002

   2,310,078       14.57

Granted

   35,000       22.26

Exercised

   (372,078 )     7.10

Forfeited

   (35,000 )     18.86
    

 

Outstanding at December 31, 2003

   1,938,000       16.07

Granted

   910,000       22.17

Exercised

   (385,000 )     12.79
    

 

Outstanding at December 31, 2004

   2,463,000     $ 18.84
    

 

Options exercisable at:

            

December 31, 2002

   711,078     $ 7.83
    

 

December 31, 2003

   509,000     $ 9.68
    

 

December 31, 2004

   1,154,000     $ 14.65
    

 

 

The following table provides additional information regarding unit options outstanding at December 31, 2004:

 

Range

of Strike

Prices


   Options
outstanding at
December 31,
2004


  

Weighted

Average
Remaining
Contractual
Life (in Years)


  

Weighted
Average
Strike
Price


   Options Exercisable at
December 31, 2004


            Number
Exercisable at
December 31,
2004


   Weighted
Average
Strike
Price


  $7.75 - $9.00

   224,000    4.75    $ 8.44    224,000    $ 8.44

$11.63 - $12.56

   110,000    5.91      12.00    110,000      12.00

$15.93 - $17.63

   755,000    6.11      16.16    750,000      16.15

$20.00 - $24.73

   1,374,000    8.82      22.55    70,000      22.64
    
              
      
     2,463,000                1,154,000       
    
              
      

 

The weighted-average fair value of EPD options granted during 2004, 2003 and 2002 was $2.26, $2.17 and $3.12 per option, respectively.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

15. COMMITMENTS AND CONTINGENCIES

 

Redelivery Commitments

 

We store and transport NGL, petrochemical and natural gas volumes for third parties under various processing, storage, transportation and similar agreements. Under the terms of these agreements, we are generally required to redeliver volumes to the owner on demand. We are insured for any physical loss of such volumes due to catastrophic events. At December 31, 2004, NGL and petrochemical volumes aggregating 13.5 million barrels were due to be redelivered to their owners along with 18,038 BBtus of natural gas.

 

Commitments under equity compensation plans of EPCO

 

In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for EPD (see Note 13). This includes the costs associated with equity-based awards granted to these employees. At December 31, 2004, there were 2,463,000 options outstanding to purchase common units under EPCO’s 1998 Plan that had been granted to employees for which we are responsible for reimbursing EPCO for the costs of such awards. The weighted-average strike price of the unit option awards granted was $18.84 per common unit. At December 31, 2004, 1,154,000 of these unit options were exercisable. An additional 374,000, 25,000 and 910,000 of these unit options will be exercisable in 2005, 2006 and 2008, respectively. As these options are exercised, we will reimburse EPCO in the form of a special cash distribution for the difference between the strike price paid by the employee and the actual purchase price paid for the units awarded to the employee. See Note 14 for additional information regarding our accounting for unit options.

 

Other commitments

 

The following table summarizes our various contractual obligations at December 31, 2004. A description of each type of contractual obligation follows.

 

    Payment or Settlement due by Period

Contractual Obligations


  Total

  2005

  2006

  2007

  2008

  2009

  Thereafter

Scheduled maturities of long-term debt

  $ 4,655,131   $ 18,450   $ 3,802   $ 504,045   $ 4,242   $ 825,576   $ 3,299,016

Operating lease obligations

  $ 88,899   $ 15,012   $ 13,328   $ 12,294   $ 9,496   $ 5,418   $ 33,351

Purchase obligations:

                                         

Product purchase commitments:

                                         

Estimated payment obligations:

                                         

Natural gas

  $ 1,160,829   $ 165,120   $ 142,133   $ 142,133   $ 142,522   $ 142,133   $ 426,788

NGLs

  $ 174,281   $ 42,664   $ 10,968   $ 10,968   $ 10,968   $ 10,968   $ 87,745

Petrochemicals

  $ 1,791,983   $ 1,010,907   $ 667,288   $ 107,540   $ 6,248            

Other

  $ 166,706   $ 41,706   $ 32,179   $ 30,092   $ 28,690   $ 18,155   $ 15,884

Underlying major volume commitments:

                                         

Natural gas (in BBtus)

    149,705     21,855     18,250     18,250     18,300     18,250     54,800

NGLs (in MBbls)

    5,657     1,267     366     366     366     366     2,926

Petrochemicals (in MBbls)

    27,294     15,559     10,126     1,520     89            

Service payment commitments

  $ 7,580   $ 4,906   $ 2,038   $ 636                  

Capital expenditure commitments

  $ 69,288   $ 69,288                              

 

Long-term debt-related commitments . We have long and short-term payment obligations under credit agreements such as our Senior Notes and revolving credit facilities. The preceding table shows our scheduled

 

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future maturities of long-term debt principal (including current maturities) for the periods indicated. See Note 9 for a description of these debt obligations and classification used for accounting purposes.

 

Operating lease commitments . We lease certain property, plant and equipment under noncancelable and cancelable operating leases. The preceding table shows the minimum lease payment obligations under our third-party operating leases with terms in excess of one year for the periods indicated.

 

Our material agreements consist of operating leases, with original terms ranging from 5 to 24 years, for natural gas and NGL underground storage facilities. We generally have the option to renew these leases, under the terms of the agreements, for one or more renewal terms ranging from 2 to 10 years. In general, rent is determined by multiplying a storage quantity (typically in barrels) by a contractually stated price. Rental payments under our storage leases are escalated, as specified in the lease, to reflect increases in the market value of the storage capacity or to adjust for inflation. In general, contingent rental payments are assessed when our storage volumes exceed our storage allotment and are equal to the product of (i) a contractually stated price and (ii) the volume which exceeds our storage allotment.

 

Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. Under certain of our natural gas and NGL storage lease agreements, we are required to perform routine maintenance on the storage facility. In addition, certain leases give us the option to increase storage capacity or fund major leasehold improvements. Maintenance, repairs and minor renewals are charged to operations as incurred. We have not made any major leasehold improvements with regards to our natural gas and NGL underground storage facilities during the years ended December 31, 2004, 2003 or 2002.

 

The operating lease commitments shown in the preceding table exclude the non-cash related party expense associated with various equipment leases contributed to us by EPCO at our formation for which EPCO has retained the liability (the “retained leases”). The retained leases are accounted for as operating leases by EPCO. EPCO’s minimum future rental payments under these leases are $2.1 million for each of the years 2005 through 2008, $0.7 million for each of the years 2009 through 2015 and $0.3 million for 2016.

 

EPCO has assigned to the Operating Partnership the purchase options associated with the retained leases. During 2004 we purchased an isomerization unit and related equipment for $17.8 million pursuant to their purchase options, which prices approximated fair value. Should we decide to exercise all of the remaining purchase options associated with the retained leases (which are also at fair value), up to an additional $2.3 million would be payable in 2008 and $3.1 million in 2016.

 

Third-party lease and rental expense included in operating income for the years ended December 31, 2004, 2003 and 2002 was approximately $19.5 million, $17.8 million and $16.4 million, respectively.

 

Purchase obligations . We define purchase obligations as agreements to purchase goods or services that are enforceable and legally binding (unconditional) and 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. We have classified our unconditional purchase obligations into the following categories:

 

   

Product purchase commitments . We have long and short-term product purchase obligations for NGLs, petrochemicals and natural gas with several third-party suppliers. The purchase prices that we are generally obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table shows our volume commitments and estimated payment obligations under these contracts for the periods indicated. At December 31, 2004, we do not have any product purchase commitments with fixed or minimum pricing provisions having remaining terms in excess of

 

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one year. To the extent that variable price provisions exist in these contracts, our estimated future payment obligations are based on the contractual price under each contract for purchases made at December 31, 2004 applied to future volume commitments.

 

    Service contract commitments . We have long and short-term commitments to pay third-party service providers for services such as maintenance agreements. Our contractual payment obligations vary by contract. The preceding table shows our future payment obligations under these service contracts.

 

    Capital expenditure commitments . We have short-term payment obligations relating to capital projects we have initiated and are also responsible for our share of such obligations associated with capital projects of our unconsolidated affiliates. These commitments represent unconditional payment obligations that we or our unconsolidated affiliates have agreed to pay vendors for services rendered or products purchased. The preceding table shows these combined amounts for the periods indicated.

 

Litigation

 

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

 

We own a facility that historically produced MTBE, a motor gasoline additive that enhances octane and is used in reformulated motor gasoline. We operated the facility, which is located within our Mont Belvieu complex. The production of MTBE was primarily driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990. In recent years, MTBE has been detected in water supplies. The major source of ground water contamination appears to be leaks from underground storage tanks. As a result of environmental concerns, several states enacted legislation to ban or significantly limit the use of MTBE in motor gasoline within their jurisdictions. In addition, federal legislation has been drafted to ban MTBE and replace the oxygenate with renewable fuels such as ethanol.

 

A number of lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing MTBE, although generally such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary which owns the facility. It is possible, however, that MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

 

Performance Guaranty

 

In December 2004, our Independence Hub, LLC subsidiary entered into the Independence Hub Agreement (the “Agreement”) with six oil and natural gas producers. The Agreement obligates Independence Hub, LLC (i) to construct an offshore platform production facility to process 850 MMcf/d of natural gas and condensate and (ii) to process certain natural gas and condensate production of the six producers following construction of the platform facility.

 

In conjunction with the Agreement, the Operating Partnership guaranteed the performance of its Independence Hub, LLC subsidiary under the Hub Agreement up to $397.5 million. In December 2004, 20% of this guaranteed amount was assumed by Cal Dive, our joint venture partner in the Independence Hub project. The remaining $318 million represents our share of the anticipated cost of the platform facility. This amount

 

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represents the cap on the Operating Partnership’s potential obligation to the six producers for our share of the cost of constructing the platform in the very unlikely scenario where the six producers take over the construction of the platform facility. The Operating Partnership’s performance guarantee continues until the earlier to occur of (i) all of the guaranteed obligations of Independence Hub, LLC shall have been terminated or expired, or shall have been indefeasibly paid or otherwise performed or discharged in full, (ii) upon mutual written consent of the Operating Partnership and the producers or (iii) mechanical completion of the production facility. We expect that mechanical completion will occur on or about November 1, 2006; therefore, we anticipate that the performance guaranty will exist until at least this forecast date.

 

In accordance with FIN 45, we recorded the fair value of the performance guaranty using an expected present value approach. Given the remote probability that the Operating Partnership would be required to perform under the guaranty, we have estimated the fair value of the performance guaranty at approximately $1.2 million, which is a component of current and other long-term liabilities on our Consolidated Balance Sheet at December 31, 2004.

 

16. SUPPLEMENTAL CASH FLOW DISCLOSURE

 

The following table provides information regarding (i) the net effect of changes in our operating assets and liabilities; (ii) cash payments for interest and (iii) cash payments for federal and state income taxes for the periods indicated.

 

     For Year Ended December 31,

 
     2004

    2003

    2002

 

(Increase) decrease in:

                        

Accounts and notes receivable

   $ (451,000 )   $ (54,480 )   $ (127,257 )

Inventories

     (44,202 )     49,932       (84,253 )

Prepaid and other current assets

     2,726       11,073       15,959  

Long-term receivables

     611       —         —    

Other assets

     (6,684 )     640       (2,930 )

Increase (decrease) in:

                        

Accounts payable

     108,458       (4,680 )     23,901  

Accrued gas payable

     286,089       128,050       262,527  

Accrued expenses

     8,800       (16,677 )     7,884  

Accrued interest

     2,617       15,012       5,369  

Other current liabilities

     6,268       (3,997 )     (7,499 )

Other liabilities

     (4,137 )     (610 )     (504 )
    


 


 


Net effect of changes in operating accounts

   $ (90,454 )   $ 124,263     $ 93,197  
    


 


 


Cash payments for interest, net of $2,766, $1,595 and $1,083 capitalized in 2004, 2003 and 2002, respectively

   $ 138,830     $ 112,712     $ 82,535  
    


 


 


Cash payments for federal and state income taxes

   $ 182     $ 453       n/a  
    


 


 


 

During 2004, we completed several business combinations, primarily the GulfTerra Merger and our purchase of certain midstream energy assets located in South Texas from El Paso. See Note 4 for the preliminary purchase price allocations related to these transactions which include non-cash consideration for EPD equity interests issued and the fair values of assets acquired and liabilities assumed.

 

We incurred liabilities for construction in progress and property additions that had not been paid at December 31, 2004, 2003 and 2002 of $62.4 million, $9.1 million and $6.5 million, respectively. Such amounts

 

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are not included under the caption “Capital expenditures” on the Statements of Consolidated Cash Flows. The increase in such amounts at December 31, 2004 compared to December 31, 2003 is primarily due our acquisition of GulfTerra, which had several large offshore projects.

 

On certain of our capital projects, third parties may be obligated to reimburse us for capital expenditures. As a result of completing the GulfTerra Merger, the number of such arrangements has increased, particularly for projects involving pipeline construction and production well tie-ins. In November 2004, Tennessee Gas Pipeline reimbursed us $7 million for construction costs incurred for our Independence Trail pipeline project, which is reflected as a source of investing cash inflows under the caption “Contributions in aid of construction” on our Statements of Consolidated Cash Flows. In addition to this reimbursement, we received $1.9 million, $0.9 million and $4 million as contributions in aid of construction during 2004, 2003 and 2002, respectively.

 

During 2003, we completed several business acquisitions, made adjustments to the 2002 purchase price allocation of the Mid-America and Seminole acquisitions and consolidated entities that had not been previously accounted for using the equity method. During 2002, we completed $1.8 billion in business acquisitions, the most significant of which were the acquisition of interests in the Mid-America and Seminole pipelines from Williams and propylene fractionation and NGL and petrochemical storage assets from Diamond-Koch. These transactions and events over the last three years affected various balance sheet categories summarized as follows:

 

     For Year Ended December 31,

 
     2004

    2003

    2002

 

Current assets

   $ 216,195     $ 24,960     $ 53,287  

Property, plant and equipment

     4,806,941       131,452       1,507,243  

Investments in unconsolidated affiliates

     160,075       (57,172 )     7,550  

Intangible assets

     744,354       4,057       92,356  

Goodwill

     376,770       880       73,691  

Deferred tax asset

                     17,307  

Other assets

     26,881       3,208       2,699  

Current liabilities

     (233,864 )     (32,140 )     (17,747 )

Long-term debt

     (2,015,583 )             (60,000 )

Other liabilities

     (47,880 )     (6,063 )     (90 )

Minority interest

     (2,422,833 )     (31,834 )     (55,569 )
    


 


 


Total

   $ 1,611,056     $ 37,348     $ 1,620,727  
    


 


 


 

Additionally, we record various financial instruments relating to commodity positions and interest rate hedging activities at their respective fair values using mark-to-market accounting. These amounts for 2004 and 2003 were negligible; however, during 2002, we recognized a net $10.2 million in non-cash mark-to-market decreases in the fair value of these instruments primarily in our commodity financial instruments portfolio.

 

Net income for 2004 includes a gain on sale of assets of approximately $15.1 million related to the satisfaction of certain requirements of a sale agreement whereby a 50% interest in Cameron Highway was sold. Approximately $10.1 million of this gain was the non-cash recognition of a receivable that is due no later than December 31, 2006 while $5.0 million of the gain was associated with a cash payment received during the fourth quarter of 2004.

 

Cash and cash equivalents (as shown on our Statements of Consolidated Cash Flows) excludes restricted cash amounts held by a brokerage firm as margin deposits associated with our financial instruments portfolio and for our physical purchase of natural gas made on the NYMEX exchange. The restricted cash balance at December 31, 2004 and 2003 was $26.2 million and $13.9 million, respectively.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

17. FINANCIAL INSTRUMENTS

 

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

 

We recognize financial instruments as assets and liabilities on our Consolidated Balance Sheets based on fair value. Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.

 

Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings.

 

To qualify as a hedge, the item to be hedged must be exposed to commodity or interest rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS No. 133, “ Accounting for Derivative Instruments and Hedging Activities ” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge is recorded in current earnings.

 

Due to the complexity of SFAS No. 133 (as amended and interpreted), the FASB is continuing to provide guidance regarding the implementation of this accounting standard. Since this guidance is still continuing, our conclusions about the application of SFAS No. 133 may be altered, which may result in adjustments being recorded in future periods as we adopt new FASB interpretations of this standard.

 

Interest rate risk hedging program

 

Our interest rate exposure results from variable and fixed rate borrowings under debt agreements. We assess the cash flow risk related to interest rates by identifying and measuring changes in our interest rate exposures that may impact future cash flows and evaluating hedging opportunities to manage these risks. We use analytical techniques to measure our exposure to fluctuations in interest rates, including cash flow sensitivity analysis models to forecast the expected impact of changes in interest rates on our future cash flows. Management oversees the strategies associated with these financial risks and approves instruments that are appropriate for our requirements.

 

We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. We believe that it is prudent to maintain an appropriate balance of variable rate and fixed rate debt in the current business climate.

 

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Fair value hedges—Interest rate swaps . In January 2004, we entered into three interest rate swap agreements with an aggregate notional amount of $250 million in which we exchanged the payment of fixed rate interest on a portion of the principal outstanding under Senior Notes B and C for variable rate interest. During the fourth quarter of 2004, we entered into six additional interest rate swap agreements with an aggregate notional amount of $600 million related to a portion of the principal outstanding under Senior Notes G issued on October 4, 2004.

 

Hedged Fixed Rate Debt


  Number
Of Swaps


 

Period Covered

by Swap


  Termination
Date of Swap


  Fixed to
Variable Rate (1)


  Notional
Amount


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

  1   Jan. 2004 to Feb. 2011   Feb. 2011   7.50% to 6.3%   $ 50 million

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

  2   Jan. 2004 to Feb. 2013   Feb. 2013   6.375% to 4.9%   $ 200 million

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

  6   4th Qtr. 2004 to Oct. 2014   Oct. 2014   5.6% to 3.4%   $ 600 million

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

 

We have designated these nine interest rate swaps as fair value hedges under SFAS No. 133 since they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense.

 

These nine agreements have a combined notional amount of $850 million and match the maturity dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a variable interest rate based on six-month LIBOR rates (plus an applicable margin as defined in each swap agreement) and receive back from the counterparty a fixed interest rate payment based on the stated interest rate of the debt being hedged, with both payments calculated using the notional amounts stated in each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”). The settlement amount is amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.

 

Total fair value of the interest rate swaps in effect at December 31, 2004 was a receivable of approximately $0.5 million with an offsetting increase in fair value of the underlying debt. Interest expense in our Statements of Consolidated Operations and Comprehensive Income for the year ended December 31, 2004 reflects a $9.1 million benefit from these swap agreements.

 

Cash flow hedges—Forward starting interest rate swaps . During the first nine months of 2004, we entered into eight forward starting interest rate swap transactions having an aggregate notional amount of $2 billion in anticipation of our financing activities associated with closing the GulfTerra Merger. Our purpose in entering into these transactions was to effectively hedge the underlying U.S. treasury rate related to our anticipated issuance of $2 billion in principal amount of fixed rate debt. On October 4, 2004, our Operating Partnership issued $2 billion of private debt securities under Senior Notes E, F, G and H. Each of the forward starting swaps was designated as a cash flow hedge under SFAS No. 133.

 

In April 2004, we elected to terminate the initial four forward starting swaps in order to manage and maximize the value of the swaps and to reduce future debt service costs. As a result, we received $104.5 million in cash from the counterparties. In September 2004, we settled the remaining four swaps resulting in an $85.1 million payment to the counterparties. The net gain of $19.4 million from these settlements will be reclassified from Accumulated Other Comprehensive Income to reduce interest expense over the life of the associated debt.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table shows the notional amount covered by each forward starting swap and the cash gain (loss) associated with each swap upon settlement (dollars in thousands):

 

Term of Anticipated Debt Offering
(or Forecasted Transaction)


   Notional
Amount of
Debt covered by
Forward
Starting Swaps


   Net Cash
Received upon
Settlement of
Forward
Starting Swaps


 

3-year, fixed rate debt instrument

   $ 500,000    $ 4,613  

5-year, fixed rate debt instrument

     500,000      7,213  

10-year, fixed rate debt instrument

     650,000      10,677  

30-year, fixed rate debt instrument

     350,000      (3,098 )
    

  


Total

   $ 2,000,000    $ 19,405  
    

  


 

Commodity risk hedging program

 

The prices of natural gas, NGLs and petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the risks associated with natural gas and NGLs, we may enter into commodity financial instruments. The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas or NGLs. The commodity financial instruments we utilize may be settled in cash or with another financial instrument. Historically, we have not hedged our exposure to risks associated with petrochemical products, including MTBE.

 

We have adopted a policy to govern our use of commodity financial instruments to manage the risks of our natural gas and NGL businesses. The objective of this policy is to assist us in achieving our profitability goals while maintaining a portfolio with an acceptable level of risk, defined as remaining within the position limits established by the Company. We may enter into risk management transactions to manage price risk, basis risk, physical risk or other risks related to our commodity positions on both a short-term (less than 30 days) and long-term basis, not to exceed 24 months. Management oversees our strategies associated with physical and financial risks (such as those mentioned previously), approves specific activities subject to the policy (including authorized products, instruments and markets) and establishes specific guidelines and procedures for implementing and ensuring compliance with the policy.

 

At December 31, 2004, we had a limited number of commodity financial instruments in our portfolio, which primarily consisted of natural gas cash flow and fair value hedges. We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific exposure. When this occurs, we may enter into a new commodity financial instrument to reestablish the economic hedge to which the closed instrument relates.

 

We recorded $0.4 million of income related to our commodity hedging activities during 2004 and an expense of $0.6 million during 2003, which are included in our operating costs and expenses in the Statements of Consolidated Operations and Comprehensive Income.

 

During 2002, we recognized a loss of $51.3 million from our commodity hedging activities that was recorded as an increase in our operating costs and expenses. Beginning in late 2000 and extending through March 2002, a large number of our commodity hedging transactions were based on the historical relationship between

 

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natural gas and NGL prices. This type of hedging strategy utilized the forward sale of natural gas at a fixed price with the expected margin on the settlement of the position offsetting or mitigating changes in the anticipated margins on NGL marketing activities and the market values of our equity NGL production. Throughout 2001, this strategy proved very successful (as the price of natural gas declined relative to our fixed positions) and was responsible for most of the $101.3 million in commodity hedging income we recorded during 2001.

 

In late March 2002, the effectiveness of this strategy was reduced due to an unexpected rapid increase in natural gas prices whereby the loss in the value of our fixed-price natural gas financial instruments was not offset by increased natural gas processing margins. Due to the inherent uncertainty surrounding natural gas prices at the time, we decided that it was prudent to exit this strategy, and we did so by late April 2002. The increased ineffectiveness of this strategy is the primary reason for the $51.3 million in commodity hedging losses recorded during 2002.

 

We had a limited number of commodity financial instruments open at December 31, 2004 and 2003. The fair value of these open positions at December 31, 2004 and 2003 was an asset of $219 thousand and $4 thousand, respectively (both amounts based on market prices on these dates).

 

Effect of financial instruments on Accumulated Other Comprehensive Income (Loss)

 

The following table summarizes the effect of our cash flow hedging financial instruments on accumulated other comprehensive income (loss) since January 1, 2002.

 

     Commodity
Financial
Instruments


   Interest Rate Fin. Instrs.

   

Accumulated

Other
Comprehensive
Income (Loss)
Balance


 
        Treasury
Locks


    Forward-
Starting
Interest
Rate Swaps


   

Balance, January 1, 2002

          $ —               $ —    

Change in fair value of treasury locks

            (3,560 )             (3,560 )
           


         


Balance, December 31, 2002

            (3,560 )             (3,560 )

Reclassification of change in fair value of treasury locks

            3,560               3,560  

Gain on settlement of treasury locks

            5,354               5,354  

Reclassification of gain on settlement of treasury locks to interest expense

            (364 )             (364 )
           


         


Balance, December 31, 2003

            4,990               4,990  

Gain on settlement of forward-starting interest rate swaps

                  $ 104,531       104,531  

Loss on settlement of forward-starting interest rate swaps

                    (85,126 )     (85,126 )

Change in fair value of commodity financial instrument

   $ 1,434                      1,434  

Reclassification of gain on settlement of treasury locks to interest expense

            (418 )             (418 )

Reclassification of gain on settlement of forward-starting swaps to interest expense

                    (857 )     (857 )
    

  


 


 


Balance, December 31, 2004

   $ 1,434    $ 4,572     $ 18,548     $ 24,554  
    

  


 


 


 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

During 2005, we will reclassify $0.4 million and $3.6 million from Accumulated Other Comprehensive Income as a reduction in interest expense from our treasury locks and forward-starting interest rate swaps, respectively. In addition, in the first quarter of 2005, we will record an approximate $1.6 million gain into income from Accumulated Other Comprehensive Income related to a commodity cash flow hedge acquired in the GulfTerra Merger. This gain is primarily due to an increase in fair value from that recorded for the commodity cash flow hedge at December 31, 2004.

 

Fair value information

 

Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair value due to their short-term nature. The estimated fair value of our fixed rate debt is estimated based on quoted market prices for such debt or debt of similar terms and maturities. The carrying amounts of our variable rate debt obligations reasonably approximate their fair values due to their variable interest rates. The fair values associated with our commodity and interest rate hedging financial instruments were developed using available market information and appropriate valuation techniques. The following table summarizes the estimated fair values of our various financial instruments at December 31, 2004 and 2003:

 

     December 31, 2004

   December 31, 2003

Financial Instruments


   Carrying
Value


   Fair
Value


   Carrying
Value


   Fair
Value


Financial assets:

                           

Cash and cash equivalents

   $ 51,163    $ 51,163    $ 44,317    $ 44,317

Accounts receivable

     1,083,526      1,083,526      462,533      462,533

Commodity financial instruments (1)

     3,904      3,904      358      358

Interest rate hedging financial instruments (2)

     505      505              

Financial liabilities:

                           

Accounts payable and accrued expenses

     1,468,933      1,468,933      801,498      801,498

Fixed-rate debt (principal amount)

     4,091,902      4,289,084      1,734,000      1,849,327

Variable-rate debt

     563,229      563,229      410,000      410,000

Commodity financial instruments (1)

     3,685      3,685      355      355

(1) Represent commodity financial instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.
(2) Represent interest rate hedging financial instrument transactions that had not settled. Settled transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.

 

Counterparty risk

 

From time to time, we have credit risk with our counterparties in terms of settlement risk associated with financial instruments. On all transactions where we are exposed to credit risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. Generally, we do not require collateral and we do not anticipate nonperformance by our counterparties.

 

18. SEGMENT INFORMATION

 

Business segments are components of a business about which separate financial information is available. The components are regularly evaluated by our CEO in deciding how to allocate resources and in assessing

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments.

 

As a result of the GulfTerra Merger (see Note 4), we have reorganized our business activities into four reportable business segments, as discussed below. Our business segments are generally organized and managed according to the type of services rendered and products produced and/or sold. We have revised our prior segment information in order to conform to the current business segment operations and presentation.

 

We have segregated our business activities into four reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services, and Petrochemical Services. Our business segments are generally organized and managed according to the type of services rendered (or technology or process employed) and products produced and/or sold, as applicable.

 

The Offshore Pipelines & Services business segment consists of (i) approximately 1,150 miles of offshore natural gas pipelines strategically located to serve production areas in some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 800 miles of Gulf of Mexico offshore crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico, which are included in our Offshore Pipelines & Services business segment.

 

The Onshore Natural Gas Pipelines & Services business segment consists of approximately 17,200 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, this segment includes two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast domestic natural gas markets. This segment also includes leased natural gas storage facilities located in Texas and Louisiana.

 

The NGL Pipelines & Services business segment includes our (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,775 miles and related storage facilities, which include our strategic Mid-America and Seminole NGL pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes our import and export terminaling operations.

 

The Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex, and an octane additive production facility. This segment also includes various petrochemical pipeline systems.

 

The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings we received from GulfTerra GP and our underlying investment in this entity at December 31, 2003. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger. Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours. Since the historical equity earnings of GulfTerra GP were based on net income amounts allocated to it by GulfTerra, it is impractical for us to allocate the equity income we received during the periods presented to each of our new business segments. Therefore, we have segregated equity earnings from GulfTerra GP from our other segment results to aid in comparability between the periods presented.

 

We operate predominantly in the midstream energy sector which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. As such, our results of operations, cash flows and financial condition may be affected by changes in the prices of these hydrocarbon products and by changes in the relative price levels among these hydrocarbon products. In general, the prices of natural gas,

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are impossible to control.

 

Our profitability could be impacted by a decline in the volume of natural gas, NGLs and crude oil transported, gathered or processed at our facilities. A material decrease in natural gas or crude oil production or crude oil refining, as a result of depressed commodity prices, a decrease in exploration and development activities or otherwise, could result in a decline in the volume of natural gas, NGLs and crude oil handled by our facilities. A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of general economic conditions, reduced demand by consumers for the end products made with NGL products, increased competition from petroleum-based products due to the pricing differences, adverse weather conditions, government regulations affecting prices and production levels of natural gas or the content of motor gasoline or other reasons, could also adversely affect our results of operations, cash flows and financial position.

 

Our revenues are derived from a wide customer base. All consolidated revenues were earned in the United States. Most of our plant-based operations are located either along the western Gulf Coast in Texas, Louisiana and Mississippi or in New Mexico. Our natural gas, NGL and oil pipelines and related operations are in a number of regions of the United States including the Gulf of Mexico offshore Texas and Louisiana; the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and certain regions of the central and western United States. Our marketing activities are headquartered in Houston, Texas at our main office and service customers in a number of regions in the United States including the Gulf Coast, West Coast and Mid-Continent areas.

 

We evaluate segment performance based on segment gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

 

We define total (or consolidated) segment gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the payment obligation; (3) gains and losses on the sale of assets; and (4) 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 intercompany transactions.

 

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

 

We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers, which may be a supplier of raw materials or a consumer of finished products. This method of operation also enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations. For example, we use the Promix NGL fractionator to process a portion of the mixed NGLs extracted by our gas plants. Another example is our use of the Dixie pipeline to transport propane sold to customers through our NGL marketing activities. See Note 13 for additional information regarding our related party relationships with unconsolidated affiliates.

 

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Index to Financial Statements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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

 

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

 

     Year Ended December 31,

 
     2004

    2003

    2002

 

Revenues (1)

   $ 8,321,202     $ 5,346,431     $ 3,584,783  

Less operating costs and expenses (1)

     (7,904,336 )     (5,046,777 )     (3,382,839 )

Add:  Equity in income (loss) of unconsolidated affiliates (1)

     52,787       (13,960 )     35,253  

Depreciation and amortization in operating costs and expenses (2)

     193,734       115,643       86,028  

Retained lease expense in operating costs and expenses (3)

     7,705       9,094       9,125  

Gain on sale of assets in operating costs and expenses (2)

     (15,901 )     (16 )     (1 )
    


 


 


Total segment gross operating margin

   $ 655,191     $ 410,415     $ 332,349  
    


 


 



(1) These amounts are taken from our Statements of Consolidated Operations and Comprehensive Income.
(2) These non-cash expenses are taken from the operating activities section of our Statements of Consolidated Cash Flows.
(3) These non-cash expenses represent the value of the operating leases contributed by EPCO to us for which EPCO has retained the cash payment obligation (i.e., the “retained leases”). The value of the retained leases contributed directly to us is shown on our Statements of Consolidated Cash Flows under the line item titled “Operating lease expense paid by EPCO.”

 

A reconciliation of our measurement of total segment gross operating margin to GAAP operating income and income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles follows:

 

     Year Ended December 31,

 
     2004

    2003

    2002

 

Total segment gross operating margin

   $ 655,191     $ 410,415     $ 332,349  

Adjustments to reconcile total segment gross operating margin to operating income:

                        

Depreciation and amortization in operating costs and expenses

     (193,734 )     (115,643 )     (86,028 )

Retained lease expense in operating costs and expenses

     (7,705 )     (9,094 )     (9,125 )

Gain on sale of assets in operating costs and expenses

     15,901       16       1  

General and administrative costs

     (47,264 )     (39,164 )     (44,109 )
    


 


 


Consolidated operating income

     422,389       246,530       193,088  

Other expense

     (159,459 )     (134,297 )     (94,147 )
    


 


 


Income before provision for income taxes, minority interest and cumulative effect of changes in accounting principles

   $ 262,930     $ 112,233     $ 98,941  
    


 


 


 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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

 

    Business Segments

                   
    Offshore
Pipeline
& Services


  Onshore Nat.
Gas Pipelines
& Services


    NGL
Pipelines
& Services


  Petrochem.
Services


    Non-Segmt.
Other


    Adjustments
and
Eliminations


    Consolidated
Totals


 

Revenues from third parties:

                                                   

Year ended December 31, 2004

  $ 32,168   $ 541,529     $ 5,553,895   $ 1,389,460                     $ 7,517,052  

Year ended December 31, 2003

          344,611       3,654,577     782,999                       4,782,187  

Year ended December 31, 2002

          295,709       2,246,266     560,091                       3,102,066  

Revenues from related parties:

                                                   

Year ended December 31, 2004

    535     253,194       534,279     16,142                       804,150  

Year ended December 31, 2003

          227,973       325,377     10,894                       564,244  

Year ended December 31, 2002

          146,062       311,525     25,130                       482,717  

Intersegment and intrasegment revenues:

                                                   

Year ended December 31, 2004

    358     21,436       2,077,871     249,758             $ (2,349,423 )     —    

Year ended December 31, 2003

          3,975       1,143,595     186,672               (1,334,242 )     —    

Year ended December 31, 2002

          2,271       757,311     151,880               (911,462 )     —    

Total revenues:

                                                   

Year ended December 31, 2004

    33,061     816,159       8,166,045     1,655,360               (2,349,423 )     8,321,202  

Year ended December 31, 2003

          576,559       5,123,549     980,565               (1,334,242 )     5,346,431  

Year ended December 31, 2002

          444,042       3,315,102     737,101               (911,462 )     3,584,783  

Equity in income (loss) in
unconsolidated affiliates:

                                                   

Year ended December 31, 2004

    8,859     772       9,898     1,233     $ 32,025               52,787  

Year ended December 31, 2003

    5,561     131       7,842     (27,441 )     (53 )             (13,960 )

Year ended December 31, 2002

    10,534     (58 )     15,392     9,385                       35,253  

Gross operating margin by individual
business segment and in total:

                                                   

Year ended December 31, 2004

    36,478     90,977       374,196     121,515       32,025               655,191  

Year ended December 31, 2003

    5,561     18,345       310,677     75,885       (53 )             410,415  

Year ended December 31, 2002

    10,535     22,110       181,928     117,776                       332,349  

Segment assets:

                                                   

At December 31, 2004

    648,181     3,729,650       2,753,934     469,327               230,375       7,831,467  

At December 31, 2003

          220,922       2,183,485     484,666               74,432       2,963,505  

Investments in and advances
to unconsolidated affiliates:

                                                   

At December 31, 2004

    319,463     5,251       173,883     20,567                       519,164  

At December 31, 2003

    127,605     2,519       190,682     22,006       424,947               767,759  

Intangible Assets:

                                                   

At December 31, 2004

    200,047     425,806       303,459     51,289                       980,601  

At December 31, 2003

                  215,072     53,821                       268,893  

Goodwill:

                                                   

At December 31, 2004

    62,348     290,397       32,763     73,690                       459,198  

At December 31, 2003

                  8,737     73,690                       82,427  

 

In general, our historical operating results and/or financial position have been affected by numerous acquisitions since 2002. Our most significant transaction to date was the GulfTerra Merger, which was completed on September 30, 2004. The aggregate value of the total consideration we paid or issued to complete the GulfTerra Merger was approximately $4 billion. The GulfTerra Merger and our other acquisitions were accounted for using purchase accounting; therefore, the operating results of these acquired entities are included in our financial results prospectively from their respective purchase dates.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Revenues from the sale and marketing of NGL products within the NGL Pipelines & Services business segment accounted for 67%, 68% and 65% of total consolidated revenues for the years ended December 31, 2004, 2003 and 2002, respectively. Revenues from the sale of petrochemical products within the Petrochemical Services segment accounted for 13%, 12% and 14% of total consolidated revenues for the years ended December 31, 2004, 2003 and 2002, respectively. Revenues from the onshore transportation of natural gas accounted for 11% and 12% of total consolidated revenues for the years ended December 31, 2003 and 2002.

 

19. CONDENSED FINANCIAL INFORMATION OF OPERATING PARTNERSHIP

 

The Operating Partnership and its subsidiaries conduct substantially all of our business. Currently, neither we nor EPD have any independent operations or material assets outside of those of the Operating Partnership.

 

At December 31, 2004, the Operating Partnership had $3.7 billion in outstanding debt securities represented by its Senior Notes A through H. EPD acts as guarantor of all of the Operating Partnership’s consolidated debt obligations, with the exception of the Seminole Notes and the remaining amounts outstanding under GulfTerra’s senior and senior subordinated notes. If the Operating Partnership were to default on any debt EPD guarantees, EPD would be responsible for full repayment of that obligation. EPD’s guarantee of these debt obligations is full and unconditional. These debt obligations are non-recourse to us. For additional information regarding our consolidated debt obligations, see Note 9.

 

The number and dollar amounts of reconciling items between EPD’s consolidated financial statements and those of its Operating Partnership are insignificant. The primary reconciling items between the consolidated balance sheet of the Operating Partnership and EPD’s consolidated balance sheet are treasury units EPD owns directly and minority interest. The differences in consolidated net income are primarily dividends recognized by the 1999 Trust (which are eliminated in consolidation) and minority interest.

 

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

 

     December 31,

     2004

   2003

ASSETS              

Current assets

   $ 1,425,574    $ 687,530

Property, plant and equipment, net

     7,831,467      2,963,505

Investments in and advances to unconsolidated affiliates, net

     519,164      767,759

Intangible assets, net

     980,601      268,893

Goodwill

     459,198      82,427

Deferred tax asset

     6,467      10,437

Long-term receivables

     14,931       

Other assets

     43,208      22,610
    

  

Total

   $ 11,280,610    $ 4,803,161
    

  

LIABILITIES AND PARTNERS’ EQUITY              

Current liabilities

   $ 1,582,911    $ 1,093,747

Long-term debt

     4,266,236      1,899,548

Other long-term liabilities

     63,521      14,081

Minority interest

     73,858      89,216

Partners’ equity

     5,294,084      1,706,569
    

  

Total

   $ 11,280,610    $ 4,803,161
    

  

Total Operating Partnership debt obligations guaranteed by EPD

   $ 4,267,229    $ 2,114,000
    

  

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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

 

     For Year Ended December 31,

 
     2004

    2003

    2002

 

Revenues

   $ 8,321,202     $ 5,346,431     $ 3,584,783  

Costs and expenses

     7,946,816       5,083,701       3,425,503  

Equity in income (loss) of unconsolidated affiliates

     52,787       (13,960 )     35,253  
    


 


 


Operating income

     427,173       248,770       194,533  

Other income (expense)

     (153,251 )     (133,798 )     (93,810 )
    


 


 


Income before provision for income taxes, minority interest and changes in accounting principles

     273,922       114,972       100,723  

Provision for income taxes

     (3,761 )     (5,293 )     (1,634 )
    


 


 


Income before minority interest and changes in accounting principles

     270,161       109,679       99,089  

Minority interest

     (8,072 )     (3,095 )     (2,137 )
    


 


 


Income before changes in accounting principles

     262,089       106,584       96,952  

Cumulative effect of changes in accounting principles

     10,781                  
    


 


 


Net income

   $ 272,870     $ 106,584     $ 96,952  
    


 


 


 

20. SUBSEQUENT EVENTS

 

January 2005 acquisition of El Paso’s interests in EPD and EPGP by affiliates of EPCO

 

In January 2005, an affiliate of EPCO acquired El Paso’s 9.9% membership interest in EPGP and 13,454,498 of EPD’s common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and affiliates own 100% of the membership interests of EPGP and, at March 15, 2005, approximately 38.3% of EPD’s total common units outstanding. El Paso no longer owns any interest in EPD or EPGP.

 

February 2005 EPD equity offering

 

In February 2005, EPD sold 17,250,000 common units (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005) to the public at an offering price of $27.05 per unit. Net proceeds from this offering, including EPGP’s proportionate net capital contribution of $9.1 million, were approximately $456.5 million after deducting applicable underwriting discounts, commissions and estimated offering expenses of $19.7 million. The net proceeds from this offering, including EPGP’s proportionate net capital contribution, were used to repay our 364-Day Acquisition Credit Facility, to temporarily reduce indebtedness outstanding under our Multi-Year Revolving Credit Facility and for general partnership purposes.

 

February 2005 EPD private senior notes offering

 

On February 15, 2005, the Operating Partnership sold $500 million in principal amount of senior notes in a Rule 144A private placement offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes (“Senior Notes I”) were issued at 99.379% of their principal amount and have fixed-rate interest of 5.00% and a maturity date of March 1, 2015. The 30-year notes (“Senior Note J”) were issued at 98.691% of their principal amount and have fixed-rate interest of 5.75% and a maturity date of March 1, 2035. The Operating Partnership

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A which was on March 15, 2005 and the remaining proceeds for general partnership purposes, including the temporary repayment of indebtedness outstanding under the Multi-Year Revolving Credit Facility.

 

March 2005 EPD universal shelf registration statement

 

In March 2005, EPD filed a universal shelf registration statement with the SEC registering the issuance of $4 billion of partnership equity and public debt obligations. In connection with this registration statement, EPD also registered for resale 36,572,122 common units currently owned by Shell and 4,427,878 common units that had been sold by Shell to Kayne Anderson MLP Investment Company in December 2004. EPD is obligated to register the resale of these common units under a registration rights agreement we executed with Shell in connection with our acquisition of certain of Shell’s Gulf Coast midstream energy businesses in September 1999.

 

Non-Public Investigation by the Bureau of Competition of the Federal Trade Commission

 

On February 24, 2005, an affiliate of EPCO acquired Texas Eastern Products Pipeline Company, LLC (“TEPPCO GP”) from Duke Energy Field Services, LLC. TEPPCO GP owns a 2% general partner interest in and is the general partner of TEPPCO. On March 11, 2005, the Bureau of Competition of the Federal Trade Commission delivered written notice to this affiliate’s legal advisor that it was conducting a non-public investigation to determine whether this affiliate’s acquisition of TEPPCO GP may substantially lessen competition. No filings were required under the Hart-Scott-Rodino Act in connection with the purchase of TEPPCO GP. EPCO and its affiliates may receive similar inquiries from other regulatory authorities. EPCO and its affiliates, including us, intend to cooperate fully with any such investigations and inquiries.

 

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Index to Financial Statements

SCHEDULE II

 

ENTERPRISE PRODUCTS GP, LLC.

 

VALUATION AND QUALIFYING ACCOUNTS

 

         Additions

           

Description


  

Balance At

Beginning
Of Period


 

Charged To

Costs And
Expenses


 

Charged To

Other
Accounts


    Deductions

    Balance At
End of Period


Accounts receivable—trade

                                  

Allowance for doubtful accounts

                                  

2004

   $ 20,423   $ 4,840   $ 4,158 (2)   $ (5,112 )(3)   $ 24,310

2003

     21,196     1,239     71       (2,083 )(1,3)     20,423

2002

     20,642     14     5,251 (1)     (4,711 )(3)     21,196

Inventories

                                  

Allowance for uncollectible imbalances

                                  

2004

                 8,463 (8)             8,463

Other current assets

                                  

Additional credit reserve for Enron

                                  

2002

     4,305                   (4,305 )(1)     —  

Other current liabilities

                                  

Reserve for environmental liabilities

                                  

2004

     9           115       (9 )     115

2003

     9                           9

2002

                 102       (93 )     9

Reserve for inventory gains and losses (5)

                                  

2004

     2,700     900             (2,850 )     750

2003

     1,271     3,000             (1,571 )     2,700

2002

     2,029     500             (1,258 )     1,271

Reserve for BEF turnaround accrual (6)

                                  

2004

     2,013                   (2,013 )     —  

2003

                 2,124 (4)     (111 )     2,013

Other long-term liabilities

                                  

Reserve for environmental liabilities

                                  

2004

     1,133           21,136 (7)     (265 )     22,004

2003

     135           1,061       (63 )     1,133

2002

           45     90               135

Reserve for BEF turnaround accrual (6)

                                  

2004

     5,001                   (5,001 )     —  

2003

                 5,001 (4)             5,001

(1) In December 2001, Enron North America filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As a result, we established an initial $10.6 million reserve for amounts owed to us by Enron. The Enron amounts were unsecured and the amount that we may ultimately recover, if any, is not presently determinable. Of the $10.6 million reserve established at December 31, 2001, $6.2 million offset billed amounts due from Enron recorded in “ Accounts Receivable-trade ”. The remaining initial $4.3 million reserve offset various unbilled commodity financial instrument positions, which were reclassified to “ Additional credit reserve from Enron .” As the unbilled amounts were invoiced in early 2002, the reserve was reclassified from “ Additional credit reserve from Enron ” to “ Allowance for doubtful accounts .” During 2003, the overall Enron reserve was lowered to $8.6 million as a result of management determination that a higher percentage of the billed amounts would be collected than was originally anticipated.
(2) The allowance account was increased in 2004 as a result of accounts acquired in the GulfTerra Merger.

 

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Index to Financial Statements
(3) In the normal course of business, we charged the allowance account for customer accounts that have been deemed uncollectible.
(4) We acquired an additional 33.3% interest in BEF on September 30, 2003. As a result, we began consolidating its accounts with those of our own. The beginning balances of these accounts reflect the initial September 30, 2003 balances we consolidated.
(5) In general, the inventory gain/loss reserve was established to cover anticipated net losses attributable to the storage of NGL and petrochemical products in underground storage caverns. The reserve is increased based on management’s estimate of net product storage losses. Product losses are charged against and reduce the reserve. Conversely, product gains increase the reserve. Management regularly reviews the status of the reserve and determines the appropriate level based on historical and anticipated storage well activity.
(6) As noted in footnote “4” above, we began consolidating BEF’s accounts with those of our own on September 30, 2003. On January 1, 2004, BEF changed its accounting method for planned major maintenance costs from accrue-in-advance to expense-as-incurred to conform to our accounting method. These reserves represent the short and long-term components of such estimates made under the accrue-in-advance method.
(7) The environmental reserve account was increased in 2004 as a result of accounts acquired in the GulfTerra Merger.
(8) The allowance for natural gas imbalances account was created as a result of accounts acquired in the GulfTerra Merger.

 

*    *    *    *

 

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Index to Financial Statements

Report of Independent Registered Public Accounting Firm

 

To the Unitholders of GulfTerra Energy Partners, L.P. and the Board of Directors and Stockholders of

    GulfTerra Energy Company, L.L.C., as General Partner:

 

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income and changes in accumulated other comprehensive income (loss), partners’ capital and cash flows present fairly, in all material respects, the financial position of GulfTerra Energy Partners, L.P. and its subsidiaries (the “Partnership”) at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

As discussed in Note 2 to the consolidated financial statements, the Partnership has entered into a definitive agreement to merge with Enterprise Products Partners L.P.

 

As discussed in Note 1 to the consolidated financial statements, the Partnership changed its method of accounting for asset retirement obligations and its reporting for gains or losses resulting from the extinguishment of debt effective January 1, 2003.

 

As discussed in Note 1 to the consolidated financial statements, the Partnership changed its method of accounting for the impairment or disposal of long lived assets effective January 1, 2002.

 

/s/    PricewaterhouseCoopers LLP

 

Houston, Texas

March 12, 2004

 

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GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF INCOME

(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

 

     YEAR ENDED DECEMBER 31,

 
     2003

    2002

   2001

 

Operating revenues

                       

Natural gas pipelines and plants

                       

Natural gas sales

   $ 171,738     $ 85,001    $ 59,701  

NGL sales

     121,167       32,978      —    

Gathering and transportation

     388,777       194,336      33,849  

Processing

     52,988       45,266      7,133  
    


 

  


       734,670       357,581      100,683  
    


 

  


Oil and NGL logistics

                       

Oil sales

     2,231       108      —    

Oil transportation

     26,769       8,364      7,082  

Fractionation

     22,034       26,356      25,245  

NGL storage

     2,816       2,817      —    
    


 

  


       53,850       37,645      32,327  
    


 

  


Platform services

     20,861       16,672      15,385  

Natural gas storage

     44,297       28,602      19,373  

Other—oil and natural gas production

     17,811       16,890      25,638  
    


 

  


       871,489       457,390      193,406  
    


 

  


Operating expenses

                       

Cost of natural gas and other products

     287,157       108,819      51,542  

Operation and maintenance

     189,702       115,162      33,279  

Depreciation, depletion and amortization

     98,846       72,126      34,778  

Asset impairment charge

     —         —        3,921  

(Gain) loss on sale of long-lived assets

     (18,679 )     473      11,367  
    


 

  


       557,026       296,580      134,887  
    


 

  


Operating income

     314,463       160,810      58,519  
    


 

  


Earnings from unconsolidated affiliates

     11,373       13,639      8,449  

Minority interest income (expense)

     (917 )     60      (100 )

Other income

     1,206       1,537      28,726  

Interest and debt expense

     127,830       81,060      41,542  

Loss due to early redemptions of debt

     36,846       2,434      —    
    


 

  


Income from continuing operations

     161,449       92,552      54,052  

Income from discontinued operations

     —         5,136      1,097  

Cumulative effect of accounting change

     1,690       —        —    
    


 

  


Net income

   $ 163,139     $ 97,688    $ 55,149  
    


 

  


 

See accompanying notes.

 

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GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF INCOME—(Continued)

(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)

 

     YEAR ENDED DECEMBER 31,

     2003

   2002

   2001

Income allocation

                    

Series B unitholders

   $ 11,792    $ 14,688    $ 17,228
    

  

  

General partner

                    

Income from continuing operations

   $ 69,414    $ 42,082    $ 24,650

Income from discontinued operations

     —        51      11

Cumulative effect of accounting change

     17      —        —  
    

  

  

     $ 69,431    $ 42,133    $ 24,661
    

  

  

Common unitholders

                    

Income from continuing operations

   $ 65,155    $ 34,275    $ 12,174

Income from discontinued operations

     —        5,085      1,086

Cumulative effect of accounting change

     1,340      —        —  
    

  

  

     $ 66,495    $ 39,360    $ 13,260
    

  

  

Series C unitholders

                    

Income from continuing operations

   $ 15,088    $ 1,507    $ —  

Cumulative effect of accounting change

     333      —        —  
    

  

  

     $ 15,421    $ 1,507    $ —  
    

  

  

Basic earnings per common unit

                    

Income from continuing operations

   $ 1.30    $ 0.80    $ 0.35

Income from discontinued operations

     —        0.12      0.03

Cumulative effect of accounting change

     0.03      —        —  
    

  

  

Net income

   $ 1.33    $ 0.92    $ 0.38
    

  

  

Diluted earnings per common unit

                    

Income from continuing operations

   $ 1.30    $ 0.80    $ 0.35

Income from discontinued operations

     —        0.12      0.03

Cumulative effect of accounting change

     0.02      —        —  
    

  

  

Net income

   $ 1.32    $ 0.92    $ 0.38
    

  

  

Basic weighted average number of common units outstanding

     49,953      42,814      34,376
    

  

  

Diluted weighted average number of common units outstanding

     50,231      42,814      34,376
    

  

  

 

See accompanying notes.

 

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GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

(IN THOUSANDS)

 

     DECEMBER 31,

     2003

   2002

ASSETS              

Current assets

             

Cash and cash equivalents

   $ 30,425    $ 36,099

Accounts receivable, net

             

Trade

     43,203      90,379

Unbilled trade

     63,067      49,140

Affiliates

     47,965      83,826

Affiliated note receivable

     3,768      —  

Other current assets

     20,595      3,451
    

  

Total current assets

     209,023      262,895

Property, plant and equipment, net

     2,894,492      2,724,938

Intangible assets

     3,401      3,970

Investments in unconsolidated affiliates

     175,747      95,951

Other noncurrent assets

     38,917      43,142
    

  

Total assets

   $ 3,321,580    $ 3,130,896
    

  

LIABILITIES AND PARTNERS’ CAPITAL              

Current liabilities

             

Accounts payable

             

Trade

   $ 113,820    $ 120,140

Affiliates

     38,870      86,144

Accrued gas purchase costs

     15,443      6,584

Accrued interest

     11,199      15,028

Current maturities of senior secured term loan

     3,000      5,000

Other current liabilities

     27,035      21,195
    

  

Total current liabilities

     209,367      254,091

Revolving credit facility

     382,000      491,000

Senior secured term loans, less current maturities

     297,000      552,500

Long-term debt

     1,129,807      857,786

Other noncurrent liabilities

     49,043      23,725
    

  

Total liabilities

     2,067,217      2,179,102
    

  

Commitments and contingencies

             

Minority interest

     1,777      1,942

Partners’ capital

             

Limited partners

             

Series B preference units; 125,392 units in 2002 issued and outstanding

     —        157,584

Common units; 58,404,649 and 44,030,314 units in 2003 and 2002 issued and outstanding

     898,072      433,150

Series C units; 10,937,500 units in 2003 and 2002 issued and outstanding

     341,350      350,565

General partner

     13,164      8,553
    

  

Total partners’ capital

     1,252,586      949,852
    

  

Total liabilities and partners’ capital

   $ 3,321,580    $ 3,130,896
    

  

 

See accompanying notes.

 

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GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

(IN THOUSANDS)

 

     YEAR ENDED DECEMBER 31,

 
     2003

    2002

    2001

 

Cash flows from operating activities

                        

Net income

   $ 163,139     $ 97,688     $ 55,149  

Less cumulative effect of accounting change

     1,690       —         —    

Less income from discontinued operations

     —         5,136       1,097  
    


 


 


Income from continuing operations

     161,449       92,552       54,052  

Adjustments to reconcile net income to net cash provided by operating activities

                        

Depreciation, depletion and amortization

     98,846       72,126       34,778  

Asset impairment charge

     —         —         3,921  

Distributed earnings of unconsolidated affiliates

                        

Earnings from unconsolidated affiliates

     (11,373 )     (13,639 )     (8,449 )

Distributions from unconsolidated affiliates

     12,140       17,804       35,062  

(Gain) loss on sale of long-lived assets

     (18,679 )     473       11,367  

Loss due to write-off of unamortized debt issuance costs, premiums and discounts

     12,544       2,434       —    

Amortization of debt issuance costs

     7,498       4,443       3,608  

Other noncash items

     3,445       4,429       544  

Working capital changes, net of acquisitions and non-cash transactions

                        

Accounts receivable

     66,441       (167,536 )     (41,037 )

Other current assets

     (9,762 )     (12,612 )     125  

Other noncurrent assets

     (1,540 )     467       (10,379 )

Accounts payable

     (45,829 )     143,553       (672 )

Accrued gas purchase costs

     8,859       4,223       (2,776 )

Accrued interest

     (3,829 )     9,330       3,574  

Other current liabilities

     (8,928 )     13,086       (235 )

Other noncurrent liabilities

     (3,114 )     (377 )     (1,067 )
    


 


 


Net cash provided by continuing operations

     268,168       170,756       82,416  

Net cash provided by discontinued operations

     —         5,244       4,968  
    


 


 


Net cash provided by operating activities

     268,168       176,000       87,384  
    


 


 


Cash flows from investing activities

                        

Development expenditures for oil and natural gas properties

     (145 )     (1,682 )     (2,018 )

Additions to property, plant and equipment

     (332,019 )     (202,541 )     (508,347 )

Proceeds from the sale and retirement of assets

     77,911       5,460       109,126  

Additions to investments in unconsolidated affiliates

     (35,536 )     (38,275 )     (1,487 )

Proceeds from the sale of investments in unconsolidated affiliates

     1,355       —         —    

Repayments on note receivable

     1,238       —         —    

Cash paid for acquisitions, net of cash acquired

     (20 )     (1,164,856 )     (28,414 )
    


 


 


Net cash used in investing activities of continuing operations

     (287,216 )     (1,401,894 )     (431,140 )

Net cash provided by (used in) investing activities of discontinued operations

     —         186,477       (68,560 )
    


 


 


Net cash used in investing activities

     (287,216 )     (1,215,417 )     (499,700 )
    


 


 


 

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GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)

(IN THOUSANDS)

 

     YEAR ENDED DECEMBER 31,

 
     2003

    2002

    2001

 

Cash flows from financing activities

                        

Net proceeds from revolving credit facility

     533,564       366,219       559,994  

Repayments of revolving credit facility

     (647,000 )     (177,000 )     (581,000 )

Net proceeds from GulfTerra Holding term credit facility

     —         530,136       —    

Repayment of GulfTerra Holding term credit facility

     —         (375,000 )     —    

Repayment of GulfTerra Holding term loan

     (160,000 )     —         —    

Net proceeds from senior secured acquisition term loan

     (23 )     233,236       —    

Repayment of senior secured acquisition term loan

     (237,500 )     —         —    

Net proceeds from senior secured term loan

     299,512       156,530       —    

Repayment of senior secured term loan

     (160,000 )     —         —    

Net proceeds from issuance of long-term debt

     537,426       423,528       243,032  

Repayments of long-term debt

     (269,401 )     —         —    

Repayment of Argo term loan

     —         (95,000 )     —    

Distributions to minority interests

     (1,242 )     —         —    

Net proceeds from issuance of common units

     509,010       150,159       286,699  

Redemption of Series B preference units

     (155,673 )     —         (50,000 )

Contributions from general partner

     3,098       4,095       2,843  

Distributions to partners

     (238,397 )     (154,468 )     (106,409 )
    


 


 


Net cash provided by financing activities of continuing operations

     13,374       1,062,435       355,159  

Net cash provided by (used in) financing activities of discontinued operations

     —         (3 )     49,960  
    


 


 


Net cash provided by financing activities

     13,374       1,062,432       405,119  
    


 


 


Increase (decrease) in cash and cash equivalents

     (5,674 )     23,015       (7,197 )

Cash and cash equivalents at beginning of year

     36,099       13,084       20,281  
    


 


 


Cash and cash equivalents at end of year

   $ 30,425     $ 36,099     $ 13,084  
    


 


 


 

 

See accompanying notes.

 

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GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(IN THOUSANDS)

 

   

SERIES B

PREFERENCE

UNITS(1)


   

SERIES B

PREFERENCE

UNITHOLDERS


   

SERIES C

UNITS(2)


 

SERIES C

UNITHOLDERS


   

COMMON

UNITS


 

COMMON

UNITHOLDERS


   

GENERAL

PARTNER(3)


    TOTAL

 

Partners’ capital at January 1, 2001

  170     $ 175,668     —     $ —       31,550   $ 132,802     $ 2,601     $ 311,071  

Net income(4)

  —         17,228     —       —       —       13,260       24,661       55,149  

Other comprehensive loss

  —         —       —       —       —       (1,259 )     (13 )     (1,272 )

Issuance of common units

  —         —       —       —       8,189     286,699       —         286,699  

Issuance of unit options

  —         —                   —       2,161       —         2,161  

Redemption of Series B preference units

  (45 )     (50,000 )   —       —       —       —         —         (50,000 )

General partner contribution related to the issuance of common units

  —         —       —       —       —       —         2,843       2,843  

Cash distributions

  —         —       —       —       —       (80,903 )     (25,022 )     (105,925 )
   

 


 
 


 
 


 


 


Partners’ capital at December 31, 2001

  125     $ 142,896     —     $ —       39,739   $ 352,760     $ 5,070     $ 500,726  

Net income(4)

  —         14,688     —       1,507     —       39,360       42,133       97,688  

Issuance of Series C units

  —         —       10,938     350,000     —       —         —         350,000  

Other comprehensive loss

  —         —       —       (942 )   —       (3,364 )     (44 )     (4,350 )

Issuance of common units

  —         —       —       —       4,291     156,072       —         156,072  

Issuance of unit options

  —         —       —       —       —       89       —         89  

General partner contribution related to the issuance of Series C units and common units

  —         —       —       —       —       —         4,095       4,095  

Cash distributions

  —         —       —       —       —       (111,767 )     (42,701 )     (154,468 )
   

 


 
 


 
 


 


 


Partners’ capital at December 31, 2002

  125     $ 157,584     10,938   $ 350,565     44,030   $ 433,150     $ 8,553     $ 949,852  

Net income(4)

  —         11,792     —       15,421           66,495       69,431       163,139  

Other comprehensive loss

  —               —       (467 )   —       (2,865 )     (73 )     (3,405 )

Issuance of common units

  —         —       —       —       14,056     494,812       —         494,812  

Issuance of Series F units

  —         —       —       —       —       4,104       —         4,104  

Redemption of unit options

  —         —       —       —       319     10,094       —         10,094  

Redemption of Series B preference units

  (125 )     (169,376 )   —       1,919     —       9,686       2,098       (155,673 )

Issuance of unit options and restricted units

                                  1,687               1,687  

General partner contribution related to the issuance of common units

  —         —       —       —       —       —         3,098       3,098  

Receipt of communication assets

  —         —       —       4,100     —       18,942       233       23,275  

Cash distributions

  —         —       —       (30,188 )   —       (138,033 )     (70,176 )     (238,397 )
   

 


 
 


 
 


 


 


Partners’ capital at December 31, 2003

  —       $ —       10,938   $ 341,350     58,405   $ 898,072     $ 13,164     $ 1,252,586  
   

 


 
 


 
 


 


 



(1) In October 2003, we redeemed all of our remaining outstanding Series B preference units for $156 million.
(2) We issued 10,937,500 of our Series C units to El Paso Corporation for a value of $350 million in connection with our acquisition of the San Juan assets. A discussion of this new class of units is included in Note 8.
(3) GulfTerra Energy Company, L.L.C. is our sole general partner and is owned 50 percent by a subsidiary of El Paso Corporation and 50 percent by a subsidiary of Enterprise Products Partners, L.P.
(4) Income allocation to our general partner includes both its incentive distributions and its one percent ownership interest.

 

See accompanying notes.

 

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GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

(IN THOUSANDS)

 

COMPREHENSIVE INCOME

 

     YEAR ENDED DECEMBER 31,

 
     2003

    2002

    2001

 

Net income

   $ 163,139     $ 97,688     $ 55,149  

Other comprehensive loss

     (3,405 )     (4,350 )     (1,272 )
    


 


 


Total comprehensive income

   $ 159,734     $ 93,338     $ 53,877  
    


 


 


 

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

 

     YEAR ENDED DECEMBER 31,

 
     2003

    2002

    2001

 

Beginning balance

   $ (5,622 )   $ (1,272 )   $ —    

Unrealized mark-to-market losses on cash flow hedges arising during period

     (12,924 )     (6,428 )     (1,682 )

Reclassification adjustments for changes in initial value of derivative instruments to settlement date

     10,018       1,579       410  

Accumulated other comprehensive income (loss) from investment in unconsolidated affiliate

     (499 )     499       —    
    


 


 


Ending balance

   $ (9,027 )   $ (5,622 )   $ (1,272 )
    


 


 


 

See accompanying notes.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Organization

 

We are a publicly held Delaware master limited partnership established in 1993 for the purpose of providing midstream energy services, including gathering, transportation, fractionation, storage and other related activities for producers of natural gas and oil, onshore and offshore in the Gulf of Mexico. As of December 31, 2003, we had 58,404,649 common units outstanding representing limited partner interests and 10,937,500 Series C units outstanding representing non-voting limited partner interests. On that date, the public owned 48,020,404 common units, or 82.2 percent of our outstanding common units, and El Paso Corporation, through its subsidiaries, owned 10,384,245 common units, or 17.8 percent of our outstanding common units, all of our Series C units and 50 percent of our general partner, which owns our one percent general partner interest.

 

In May 2003, we changed our name to GulfTerra Energy Partners, L.P. from El Paso Energy Partners, L.P. and reorganized our general partner. In connection with our name change, we also changed the names of several subsidiaries in May 2003, including the following, as listed in the table below.

 

NEW NAME


  

FORMER NAME


GulfTerra Energy Finance Corporation

   El Paso Energy Partners Finance Corporation

GulfTerra Arizona Gas, L.L.C.

   El Paso Arizona Gas, L.L.C.

GulfTerra Intrastate, L.P.

   El Paso Energy Intrastate, L.P.

GulfTerra Texas Pipeline, L.P.

   EPGT Texas Pipeline, L.P.

GulfTerra Holding V, L.P.

   EPN Holding Company, L.P.

 

Our sole general partner is GulfTerra Energy Company, L.L.C., a recently-formed Delaware limited liability company that is owned 50 percent by a subsidiary of El Paso Corporation and 50 percent by a subsidiary of Enterprise, a publicly traded master limited partnership. El Paso Corporation (through its subsidiaries) owned 100 percent of our general partner until October 2003, when Goldman Sachs acquired a 9.9 percent interest in our general partner. In December 2003, El Paso Corporation reacquired Goldman Sachs’ interest in our general partner and then sold a 50 percent interest in our general partner to a subsidiary of Enterprise.

 

On December 15, 2003, we, along with Enterprise and El Paso Corporation, announced that we had executed definitive agreements to merge Enterprise and GulfTerra to form one of the largest publicly traded MLPs with Enterprise being the continuing entity. The general partner of the combined partnership will be jointly owned by affiliates of El Paso Corporation and privately-held Enterprise Products Company, with each owning a 50-percent interest.

 

The combined partnership, which will retain the name Enterprise Products Partners L.P., will serve the largest producing basins of natural gas, crude oil and NGLs in the U.S., including the Gulf of Mexico, Rocky Mountains, San Juan Basin, Permian Basin, South Texas, East Texas, Mid-Continent and Louisiana Gulf Coast basins and, through connections with third-party pipelines, Canada’s western sedimentary basin. The partnership will also serve the largest consuming regions for natural gas, crude oil and NGLs on the U.S. Gulf Coast.

 

Basis of Presentation and Principles of Consolidation

 

Our consolidated financial statements include the accounts of all majority-owned, controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. We account for investments in companies where we have the ability to exert significant influence over, but not control over operating and financial policies, using the equity method of accounting. Prior to May 2001, our general partner’s approximate one percent non-managing interest in twelve of our subsidiaries represented the minority interest in our

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

consolidated financial statements. In May 2001, we purchased our general partner’s one percent non-managing ownership interest in twelve of our subsidiaries for $8 million. As a result of this acquisition, all of our subsidiaries, but not our equity investees, are wholly-owned by us.

 

During part of 2003 and 2002, third parties had minority ownership interests in Matagorda Island Area Gathering System (MIAGS) and Arizona Gas, L.L.C. The assets, liabilities and operations of these entities are included in our consolidated financial statements and we account for the third party ownership interest as minority interest in our consolidated balance sheets and as minority interest income (expense) in our consolidated statements of income. In October 2003, we purchased the remaining 17 percent interest in MIAGS. As a result, we no longer recognize the third party ownership interest in MIAGS as minority interests in our consolidated balance sheets or consolidated statements of income.

 

Our consolidated financial statements for prior periods include reclassifications that were made to conform to the current year presentation. Those reclassifications have no impact on reported net income or partners’ capital. We have reflected the results of operations from our Prince assets disposition as discontinued operations for the years ended December 31, 2002 and 2001. See Note 2 for a further discussion of our Prince assets disposition.

 

Use of Estimates

 

The preparation of our financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of our financial statements. While we believe our estimates are appropriate, actual results can, and often do, differ from those estimates.

 

Accounting for Regulated Operations

 

Our HIOS interstate natural gas system and our Petal storage facility are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Each system operates under separate FERC approved tariffs that establish rates, terms and conditions under which each system provides services to its customers. Our businesses that are subject to the regulations and accounting requirements of FERC have followed the accounting requirements of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation, which may differ from the accounting requirements of our non-regulated entities. Transactions that have been recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects.

 

Under the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations, which we adopted on January 1, 2003, the cost associated with the retirement of long-lived assets for regulated entities accounted for under SFAS No. 71 should be classified as a regulatory liability instead of as a component of property, plant and equipment. As a result, we reclassified $13.6 million from property, plant and equipment to a regulatory liability and at December 31, 2003, this balance is included in other noncurrent liabilities in our consolidated balance sheet. Prior to January 2003, this item was reflected in accumulated depreciation, depletion and amortization and the balance for this item at December 31, 2002, was $12.9 million.

 

When the accounting method followed is required by or allowed by the regulatory authority for rate-making purposes, the method conforms to the generally accepted accounting principle (GAAP) of matching costs with the revenues to which they apply.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Cash and Cash Equivalents

 

We consider short-term investments with little risk of change in value because of changes in interest rates and purchased with an original maturity of less than three months to be cash equivalents.

 

Allowance for Doubtful Accounts

 

We have established an allowance for losses on accounts that we believe are uncollectible. We review collectibility regularly and adjust the allowance as necessary, primarily under the specific identification method. At December 31, 2003 and 2002, the allowance was $4.0 million and $2.5 million.

 

Natural Gas Imbalances

 

Natural gas imbalances result from differences in gas volumes received from and delivered to our customers and arise when a customer delivers more or less gas into our pipelines than they take out. These imbalances are settled in kind through a tracking mechanism, negotiated cash-outs between parties, or are subject to a cash-out procedure and are valued at prices representing the estimated value of these imbalances upon settlement. We estimate the value of our imbalances at prices representing the estimated value of the imbalances upon settlement. Changes in natural gas prices may impact our valuation. We do not value our imbalances based on current month-end spot prices because it is not likely that we would purchase or receive natural gas at that point in time to settle the imbalance. Natural gas imbalances are reflected in accounts receivable or accounts payable, as appropriate, in our accompanying consolidated balance sheets. Our imbalance receivables and imbalance payables were as follows at December 31 (in thousands):

 

     2003

   2002

Imbalance Receivables

             

Trade

   $ 37,228    $ 88,929

Affiliates

   $ 16,405    $ 15,460

Imbalance Payables

             

Trade

   $ 68,446    $ 104,035

Affiliates

   $ 14,047    $ 22,316

 

Property, Plant and Equipment

 

We record our property, plant and equipment at its original cost of construction or, upon acquisition, the fair value of the asset acquired. Additionally, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and, in our regulated businesses that apply the provisions of SFAS No. 71, an equity return component. We also capitalize the major units of property replacements or improvements and expense minor items including repair and maintenance costs. In addition, we reduce our property, plant and equipment balance for any amounts that we receive in the form of contributions in aid of construction.

 

For our regulated interstate system and storage facility we use the composite (group) method to depreciate regulated property, plant and equipment. Under this method, assets with similar lives and other characteristics are grouped and depreciated as one asset. We apply the depreciation rate approved in our tariff to the total cost of the group until its net book value equals its estimated salvage value. Currently, depreciation rates on our regulated interstate system and storage facility vary from 1 to 20 percent. Using these rates, the remaining depreciable lives of these assets range from 1 to 39 years.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Our non-regulated gathering pipelines, platforms and related facilities, processing facilities and equipment, and storage facilities and equipment are depreciated on a straight-line basis over the estimated useful lives which are as follows:

 

Gathering pipelines

   5-40 years

Platforms and facilities

   18-30 years

Processing facilities

   25-30 years

Storage facilities

   25-30 years

 

We account for our oil and natural gas exploration and production activities using the successful efforts method of accounting. Under this method, costs of successful exploratory wells, developmental wells and acquisitions of mineral leasehold interests are capitalized. Production, exploratory dry hole and other exploration costs, including geological and geophysical costs and delay rentals, are expensed as incurred. Unproved properties are assessed periodically and any impairment in value is recognized currently as depreciation, depletion and amortization expense.

 

Depreciation, depletion and amortization of the capitalized costs of producing oil and natural gas properties, consisting principally of tangible and intangible costs incurred in developing a property and costs of productive leasehold interests, are computed on the unit-of-production method. Unit-of-production rates are based on annual estimates of remaining proved developed reserves or proved reserves, as appropriate, for each property.

 

Estimated dismantlement, restoration and abandonment costs and estimated residual salvage values are taken into account in determining depreciation provisions for gathering pipelines, platforms, related facilities and oil and natural gas properties. At December 31, 2002, accrued abandonment costs were $24.6 million, of which $6.4 million was related to offshore wells. As discussed below, we adopted SFAS No. 143 Accounting for Asset Retirement Obligations on January 1, 2003 and the amounts accrued and capitalized were adjusted to conform to the provisions of that statement.

 

Retirements, sales and disposals of assets are recorded by eliminating the related costs and accumulated depreciation, depletion and amortization of the disposed assets with any resulting gain or loss reflected in income.

 

Accounting for Asset Retirement Obligations

 

On January 1, 2003, we adopted SFAS No. 143. The provisions of this statement relate primarily to our obligations to plug abandoned offshore wells that constitute part of our non-segment assets.

 

Upon our adoption of SFAS No. 143, we recorded (i) a $7.4 million net increase to property, plant, and equipment, relating to offshore wells, representing non-current retirement assets, (ii) a $5.7 million increase to noncurrent liabilities representing retirement obligations, and (iii) a $1.7 million increase to income as a cumulative effect of accounting change. Each retirement asset is depreciated over the remaining useful life of the long-term asset with which the retirement liability is associated. An ongoing expense is recognized for the interest component of the liability due to the changes in the value of the retirement liability as a result of the passage of time, which we reflect as a component of depreciation expense in our income statement.

 

Other than our obligations to plug and abandon wells, we cannot estimate the costs to retire or remove assets used in our business because we believe the assets do not have definite lives or we do not have the legal obligation to abandon or dismantle the assets. We believe that the lives of our assets or the underlying reserves associated with our assets cannot be estimated. Therefore, aside from the liability associated with the plugging and abandonment of offshore wells, we have not recorded liabilities relating to any of our other assets.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The pro forma income from continuing operations and amounts per common unit for the years ended December 31, 2002 and 2001, assuming the provisions of SFAS No. 143 were adopted prior to the earliest period presented, are shown below:

 

     YEARS ENDED
DECEMBER 31,


     2002

   2001

Pro forma income from continuing operations

   $ 93,932    $ 54,321
    

  

Pro forma income from continuing operations allocated to common unitholders

   $ 35,369    $ 12,446
    

  

Pro forma basic income from continuing operations per weighted average common unit

   $ 0.83    $ 0.36
    

  

Pro forma diluted income from continuing operations per weighted average common unit

   $ 0.83    $ 0.36
    

  

 

The pro forma amount of our asset retirement obligations at December 31, 2002 and 2001, assuming asset retirement obligations as provided for in SFAS No. 143 were recorded prior to the earliest period presented was $5.7 million and $5.3 million. Our asset retirement obligation for December 31, 2003, is shown below.

 

YEAR


  

LIABILITY

BALANCE

AS OF

JANUARY 1


   ACCRETION

  

OTHER

CHANGE IN

LIABILITY


   

LIABILITY BALANCE

AS OF

DECEMBER 31


     (IN THOUSANDS)

2003

   $ 5,726    $ 442    $ (246 )(1)   5,922

(1) Abandonment work performed during the year ended December 31, 2003.

 

Goodwill and Other Intangible Assets

 

We adopted the provisions of SFAS No. 142 Goodwill and Other Intangible Assets on January 1, 2002, except for goodwill and intangible assets we acquired after June 30, 2001 for which we adopted the provisions immediately. Accordingly, we record identifiable intangible assets we acquire individually or with a group of other assets at fair value upon acquisition. Identifiable intangible assets with finite useful lives are amortized to expense over the estimated useful life of the asset. Identifiable intangible assets with indefinite useful lives and goodwill are evaluated annually for impairment by comparison of their carrying amounts with the fair value of the individual assets. We recognize an impairment loss in income for the amount by which the carrying value of any identifiable intangible asset or goodwill exceeds the fair value of the specific assets. As of December 31, 2003 and 2002, we had no goodwill, other than as described below.

 

As of December 31, 2003 and 2002, the carrying amount of our equity investment in Poseidon exceeded the underlying equity in net assets by approximately $3.0 million. With our adoption of SFAS No. 142 on January 1, 2002, we no longer amortize this excess amount and will test it for impairment if an event occurs that indicates there may be a loss in value, or at least annually. Prior to January 1, 2002, we amortized this excess amount using the straight line method over approximately 30 years. This excess amount is reflected on our accompanying consolidated balance sheets in investments in unconsolidated affiliates. Our adoption of this statement did not have a material impact on our financial position or results of operations.

 

As part of our acquisition of the EPN Holding assets and the San Juan assets, we obtained intangible assets representing contractual rights under dedication and transportation agreements with producers. As of December 31, 2003 and 2002, the value of these intangible assets was approximately $3.4 million and $4.0 million and is reflected on our accompanying consolidated balance sheets as intangible assets. We amortize the intangible assets acquired in the EPN Holding asset acquisition to expense using the units-of-production method over the

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

expected lives of the reserves ranging from 26 to 45 years. We amortize the intangible assets acquired in the San Juan asset acquisition over the life of the contracts of approximately 4 years.

 

Impairment and Disposal of Long-Lived Assets

 

We apply the provisions of SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets to account for impairment and disposal of long-lived assets. Accordingly, we evaluate the recoverability of long-lived assets when adverse events or changes in circumstances indicate that the carrying value of an asset or group of assets may not be recoverable. We determine the recoverability of an asset or group of assets by estimating the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets at the lowest level for which separate cash flows can be measured. If the total of the undiscounted cash flows is less that the carrying amount for the assets, we estimate the fair value of the asset or group of assets and recognize the amount by which the carrying value exceeds the fair value, less cost to sell, as an impairment loss in income from operations in the period the impairment is determined.

 

Additionally, as required by SFAS No. 144, we classify long-lived assets to be disposed of other than by sale (e.g., abandonment, exchange or distribution) as held and used until the item is abandoned, exchanged or distributed. We evaluate assets to be disposed of other than by sale for impairment and recognize a loss for the excess of the carrying value over the fair value. Long-lived assets to be disposed of through sale recognition meeting specific criteria are classified as “Held for Sale” and measured at the lower of their cost or fair value less cost to sell. We report the results of operations of a component classified as held for sale, including any gain or loss in the period(s) in which they occur. Upon our adoption of SFAS No. 144, we reclassified our losses on the sale of long-lived assets of $0.4 million and $11.4 million for the years ended December 31, 2002 and 2001, into operating income to conform with the provisions of SFAS No. 144.

 

We also reclassify the asset or assets as either held for sale or as discontinued operations, depending on whether they have independently determinable cash flow and whether we have any continuing involvement.

 

Capitalization of Interest

 

Interest and other financing costs are capitalized in connection with construction and drilling activities as part of the cost of the asset and amortized over the related asset’s estimated useful life.

 

Debt Issue Costs

 

Debt issue costs are capitalized and amortized over the life of the related indebtedness using the effective interest method. Any unamortized debt issue costs are expensed at the time the related indebtedness is repaid or terminated. At December 31, 2003 and 2002, the unamortized amount of our debt issue costs included in other noncurrent assets was $29.2 million and $32.6 million. Amortization of debt issue costs for the years ended December 31, 2003, 2002 and 2001 were $7.5 million, $4.4 million and $3.6 million and are included in interest and debt expense on our consolidated statements of income.

 

Revenue Recognition and Cost of Natural Gas and Other Products

 

Revenue from gathering and transportation of hydrocarbons is recognized upon receipt of the hydrocarbons into the pipeline systems. Revenue from commodity sales is recognized upon delivery. Commodity storage revenues and platform access revenues consist primarily of fixed fees for capacity reservation and some of the transportation contracts on our Viosca Knoll system and our Indian Basin lateral also contain a fixed fee to reserve transportation capacity. These fixed fees are recognized during the month in which the capacity is reserved by the customer, regardless of how much capacity is actually used. Revenue from processing services, treating services and fractionation services is recognized in the period the services are provided. Interruptible

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

revenues from natural gas storage, which are generated by providing excess storage capacity, are variable in nature and are recognized when the service is provided. Other revenues generally are recorded when services have been provided or products have been delivered.

 

Prior to 2002, our cost of natural gas consisted primarily of natural gas purchased at GulfTerra Alabama Intrastate for resale. As a result of our acquisition of the EPN Holding assets and the San Juan assets, we are now incurring additional costs related to system imbalances and for the purchase of natural gas as part of our producer services activities. As a convenience for our producers, we may purchase natural gas from them at the wellhead at an index price less an amount that compensates us for our gathering services. We then sell this gas into the open market at points on our system at the same index price. We reflect these sales in our revenues and the related purchases as cost of natural gas on the accompanying consolidated statements of income.

 

Typhoon Oil Pipeline’s transportation agreement with BHP and Chevron Texaco provides that Typhoon Oil purchase the oil produced at the inlet of its pipeline for an index price less an amount that compensates Typhoon Oil for transportation services. At the outlet of its pipeline, Typhoon Oil resells this oil back to these producers at the same index price. Beginning in 2003, we record revenue from these buy/sell transactions upon delivery of the oil based on the net amount billed to the producers. We acquired the Typhoon oil pipeline in November 2002, and for the year ended December 31, 2002, we recorded revenue based on the gross amount billed to the producers. For the year ended December 31, 2002, we reclassified $10.5 million from cost of natural gas and other products to revenue to conform to our 2003 presentation. This reclassification has no effect on operating income, net income or partners’ capital.

 

As of July 1, 2003, HIOS implemented new rates, subject to a refund, and we established a reserve for our estimate of the refund obligation. We will continue to review our expected refund obligation as the rate case moves through the hearing process and may increase or decrease the amounts reserved for refund obligation as our expectation changes.

 

Environmental Costs

 

We expense or capitalize expenditures for ongoing compliance with environmental regulations that relate to past or current operations as appropriate. We expense amounts for clean up of existing environmental contamination caused by past operations which do not benefit future periods. We record liabilities when our environmental assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. These estimates are subject to revision in future periods based on actual costs or new circumstances and are included in our consolidated balance sheets in other noncurrent liabilities at their undiscounted amounts.

 

Accounting for Price Risk Management Activities

 

Our business activities expose us to a variety of risks, including commodity price risk and interest rate risk. From time to time we engage in price risk management activities for non-trading purposes to manage market risks associated with commodities we purchase and sell and interest rates on variable rate debt. Our price risk management activities involve the use of a variety of derivative financial instruments, including:

 

    exchange-traded future contracts that involve cash settlement;

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

    forward contracts that involve cash settlements or physical delivery of a commodity; and

 

    swap contracts that require payments to (or receipts from) counterparties based on the difference between a fixed and a variable price, or two variable prices, for a commodity or variable rate debt instrument.

 

We account for all of our derivative instruments in our consolidated financial statements under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. We record all derivatives in our consolidated balance sheets at their fair value as other assets or other liabilities and classify them as current or noncurrent based upon their anticipated settlement date.

 

For those instruments entered into to hedge risk and which qualify as hedges, we apply the provisions of SFAS No. 133, and the accounting treatment depends on each instrument’s intended use and how it is designated. In addition to its designation, a hedge must be effective. To be effective, changes in the value of the derivative or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged.

 

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies for undertaking various hedge transactions. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows or fair values of the hedged items. We discontinue hedge accounting prospectively if we determine that a derivative is not highly effective as a hedge or if we decide to discontinue the hedging relationship.

 

During 2003, 2002 and 2001, we entered into cash flow hedges that qualify for hedge accounting under SFAS No. 133 treatment. Changes in the fair value of a derivative designated as a cash flow hedge are recorded in accumulated other comprehensive income for the portion of the change in value of the derivative that is effective. The ineffective portion of the derivative is recorded in earnings in the current period. Classification in the income statement of the ineffective portion is based on the income classification of the item being hedged. At the date of the hedged transaction, we reclassify the gains or losses resulting from the sale, maturity, extinguishment or termination of derivative instruments designated as hedges from accumulated other comprehensive income to operating income or interest expense, as appropriate, in our consolidated statements of income. We classify cash inflows and outflows associated with the settlement of our derivative transactions as cash flows from operating activities in our consolidated statements of cash flows.

 

We also record our ownership percentage of the changes in the fair value of derivatives of our investments in unconsolidated affiliates in accumulated other comprehensive income.

 

We may also purchase and sell instruments to economically hedge price fluctuations in the commodity markets. These instruments are not documented as hedges due to their short-term nature, or do not qualify under the provisions of SFAS No. 133 for hedge accounting due to the terms in the instruments. Where such derivatives do not qualify, or are not documented, changes in their fair value are recorded in earnings in the current period.

 

In August 2002, we entered into a derivative financial instrument to hedge our exposure during 2003 to changes in natural gas prices in the San Juan Basin in anticipation of our acquisition of the San Juan assets. From August 2002 through our acquisition date, November 27, 2002, we accounted for this derivative through current earnings since it did not qualify for hedge accounting under SFAS No. 133. Beginning with the acquisition date in November 2002, we have designated this derivative as a cash flow hedge and are accounting for it as such under SFAS No. 133.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

During the normal course of our business, we may enter into contracts that qualify as derivatives under the provisions of SFAS No. 133. As a result, we evaluate our contracts to determine whether derivative accounting is appropriate. Contracts that meet the criteria of a derivative and qualify as “normal purchases” and “normal sales”, as those terms are defined in SFAS No. 133, may be excluded from SFAS No. 133 treatment.

 

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This statement amends SFAS No. 133 to incorporate several interpretations of the Derivatives Implementation Group (DIG), and also makes several minor modifications to the definition of a derivative as it was defined in SFAS No. 133. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. There was no initial financial statement impact of adopting this standard, although the FASB and DIG continue to deliberate on the application of the standard to certain derivative contracts, which may impact our financial statements in the future.

 

Income Taxes

 

As of December 31, 2003, neither we nor any of our subsidiaries are taxable entities. However, the taxable income or loss resulting from our operations will ultimately be included in the federal and state income tax returns of the general and limited partners. Individual partners will have different investment bases depending upon the timing and price of their acquisition of partnership units. Further, each partner’s tax accounting, which is partially dependent upon his tax position, may differ from the accounting followed in the consolidated financial statements. Accordingly, there could be significant differences between each individual partner’s tax basis and his share of the net assets reported in the consolidated financial statements. We do not have access to information about each individual partner’s tax attributes and the aggregate tax bases cannot be readily determined.

 

Income (Loss) per Common Unit

 

Basic income (loss) per common unit excludes dilution and is computed by dividing net income (loss) attributable to the common unitholders by the weighted average number of common units outstanding during the period. Diluted income (loss) per common unit reflects potential dilution and is computed by dividing net income (loss) attributable to the common unitholders by the weighted average number of common units outstanding during the period increased by the number of additional common units that would have been outstanding if the potentially dilutive units had been issued.

 

Basic income (loss) per common unit and diluted income (loss) per common unit are the same for the years ended December 31, 2002 and 2001, as the number of potentially dilutive units were so small as not to cause the diluted earnings per unit to be different from the basic earnings per unit.

 

Comprehensive Income

 

Our comprehensive income is determined based on net income (loss), adjusted for changes in accumulated other comprehensive income (loss) from our cash flow hedging activities associated with our GulfTerra Alabama Intrastate operations, our Indian Basin processing plant, the San Juan assets and our unconsolidated affiliate, Poseidon Oil Pipeline Company, L.L.C.

 

The following table presents our allocation of accumulated other comprehensive loss as of December 31:

 

     2003

    2002

    2001

 

Common units’ interest

   $ (7,488 )   $ (4,623 )   $ (1,259 )
    


 


 


Series C units’ interest

   $ (1,409 )   $ (942 )   $ —    
    


 


 


General partner’s interest

   $ (130 )   $ (57 )   $ (13 )
    


 


 


 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Accounting for Stock-Based Compensation

 

We use the intrinsic value method established in Accounting Principles Board Opinion (APB) No. 25, Accounting for Stock Issued to Employees, to value unit options issued to individuals who are on our general partner’s current board of directors and for those grants made prior to El Paso Corporation’s acquisition of our general partner in August 1998 under our Omnibus Plan and Director Plan. For the years ending December 31, 2003, 2002 and 2001, the cost of this stock-based compensation had no impact on our net income, as all options granted had an exercise price equal to the market value of the underlying common stock on the date of grant. We use the provisions of SFAS No. 123, Accounting for Stock-Based Compensation, to account for all of our other stock-based compensation programs.

 

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation Transition and Disclosure. This statement amends SFAS No. 123, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this statement amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the methods of accounting for stock-based employee compensation and the effect of the method used on reported results. This statement is effective for fiscal years ending after December 15, 2002. We have decided that we will continue to use APB No. 25 to value our stock-based compensation issued to individuals who are on our general partner’s current board of directors and for those grants made prior to El Paso Corporation’s acquisition of our general partner in August 1998 and will include data providing the pro forma income effect of using the fair value method as required by SFAS No. 148. We will continue to use the provisions of SFAS No. 123 to account for all of our other stock-based compensation programs.

 

If compensation expense related to these plans had been determined by applying the fair value method in SFAS No. 123 our net income allocated to common unitholders and net income per common unit would have approximated the pro forma amounts below:

 

     YEARS ENDED DECEMBER 31,

     2003

   2002

   2001

     (IN THOUSANDS)

Net income, as reported

   $ 163,139    $ 97,688    $ 55,149

Add: Stock-based employee compensation expense included in reported net income

     1,489      1,168      367

Less: Stock-based employee compensation expense determined under fair value based method

     1,532      1,912      678
    

  

  

Pro forma net income

   $ 163,096    $ 96,944    $ 54,838
    

  

  

Pro forma net income allocated to common unitholders

   $ 66,452    $ 38,616    $ 12,949
    

  

  

Earnings per common unit:

                    

Basic, as reported

   $ 1.33    $ 0.92    $ 0.38
    

  

  

Basic, pro forma

   $ 1.33    $ 0.90    $ 0.38
    

  

  

Diluted, as reported

   $ 1.32    $ 0.92    $ 0.38
    

  

  

Diluted, pro forma

   $ 1.32    $ 0.90    $ 0.38
    

  

  

 

The effects of applying SFAS No. 123 in this pro forma disclosure may not be indicative of future amounts.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Accounting for Debt Extinguishments

 

In January 2003, we adopted SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections. Accordingly, we now evaluate the nature of any debt extinguishments to determine whether to report any gain or loss resulting from the early extinguishment of debt as an extraordinary item or as a component of income from continuing operations.

 

Accounting for Costs Associated with Exit or Disposal Activities

 

In January 2003, we adopted SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. This statement impacts any exit or disposal activities that we initiate after January 1, 2003 and we now recognize costs associated with exit or disposal activities when they are incurred rather than when we commit to an exit or disposal plan. Our adoption of this pronouncement did not have an effect on our financial position or results of operations.

 

Accounting for Guarantees

 

In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, we record a liability at fair value, or otherwise disclose, certain guarantees issued after December 31, 2002, that contractually require us to make payments to a guaranteed party based on the occurrence of certain events. We have not entered into any material guarantees that would require recognition under FIN No. 45.

 

Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity

 

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement provides guidance on the classification of financial instruments, as equity, as liabilities, or as both liabilities and equity. The provisions of SFAS No. 150 are effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning July 1, 2003. We adopted the provisions of SFAS No. 150 on July 1, 2003, and our adoption had no material impact on our financial statements.

 

New Accounting Pronouncements Issued But Not Yet Adopted

 

Consolidation of Variable Interest Entities

 

In January 2003, the FASB issued FIN No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51. This interpretation defines a variable interest entity (VIE) as a legal entity whose equity owners do not have sufficient equity at risk and/or a controlling financial interest in the entity. This standard requires a company to consolidate a VIE if it is allocated a majority of the entity’s losses and/or returns, including fees paid by the entity. In December 2003, the FASB issued FIN 46-R, which amended FIN No. 46, to extend its effective date until the first quarter of 2004 for all types of entities except special purpose entities (SPE’s). In addition, FIN No. 46-R also limited the scope of FIN No. 46 to exclude certain joint ventures of other entities that meet the characteristics of businesses.

 

We have no SPE’s as defined by FIN Nos. 46 and 46-R. We have evaluated our joint ventures, unconsolidated subsidiaries and other contractual arrangements that could be considered variable interests or variable interest entities that were created before February 1, 2003 and have determined that they will not have a significant effect on our reported results and financial position when we adopt the provisions of FIN No. 46-R in the first quarter of 2004.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

2. ACQUISITIONS AND DISPOSITIONS

 

Merger with Enterprise

 

On December 15, 2003, we, along with Enterprise and El Paso Corporation, announced that we had executed definitive agreements to merge Enterprise and GulfTerra to form one of the largest publicly traded MLPs. The general partner of the combined partnership will be jointly owned by affiliates of El Paso Corporation and privately-held Enterprise Products Company, with each owning a 50-percent interest. The definitive agreements include three transactions, of which two affect us.

 

In the first transaction that effects us, which occurred with the signing of the merger agreement, a wholly owned subsidiary of Enterprise purchased a 50 percent limited-voting interest in our general partner. This interest entitles Enterprise to half of the cash distributed to our general partner, but does not allow Enterprise to elect any of our general partner’s directors or otherwise generally participate in our general partner’s management of our business.

 

The second transaction that affects us will occur at the merger date. At the closing of the merger, each outstanding GulfTerra common unit (other than those owned by Enterprise) will convert into 1.81 Enterprise common units, GulfTerra will become a wholly-owned subsidiary of Enterprise, and El Paso Corporation will acquire a 50 percent interest in Enterprise’s general partner (including the right to elect half of the directors of Enterprise’s general partner). The closing of the merger is subject to the satisfaction of specified conditions, including obtaining clearance under the Hart-Scott-Rodino Antitrust Improvement Acts, and the approval of our unitholders and Enterprise’s unitholders. Completion of the merger is expected to occur during the second half of 2004.

 

Our merger agreement with Enterprise limits our ability to raise additional capital prior to the closing of the merger without Enterprise’s approval. In addition, because the closing of the merger will be a change of control, and thus a default, under our credit facility, we will either repay or amend that facility prior to the closing. In addition, because the merger closing will constitute a change of control under our indentures, we will be required to offer to repurchase our outstanding senior subordinated notes (and possibly our senior notes) at 101 percent of their principal amount after the closing. In coordination with Enterprise, we are evaluating alternative financing plans in preparation for the close of the merger. We and Enterprise can agree on the date of the merger closing after the receipt of all necessary approvals. We do not intend to close until appropriate financing is in place.

 

If the merger agreement is terminated and (1) a business transaction between us and a third party that conflicts with the merger was proposed and certain other conditions were met or (2) we materially and willfully violated our agreement not to solicit transactions that conflict with the merger, then we will be required to pay Enterprise a termination fee of $112 million. If the merger agreement is terminated because our unitholders did not approve the merger and either (1) a possible business transaction involving us but not involving Enterprise and conflicting with the merger was publicly proposed and our board of directors publicly and timely reaffirmed its recommendations of the Enterprise merger or (2) no such possible business transaction was publicly announced, then we will be required to pay Enterprise a termination fee of $15 million. Enterprise is subject to similar termination fee requirements.

 

Exchange with El Paso Corporation

 

In connection with our November 2002 San Juan assets acquisition, El Paso Corporation retained the obligation to repurchase the Chaco plant from us for $77 million in October 2021. In October 2003, we released El Paso Corporation from that obligation in exchange for El Paso Corporation contributing specified communication assets and other rights to us. The communication assets we received are used in the operation of

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

our pipeline systems. Prior to the October 2003 exchange, we had access to these assets under our general and administrative services agreement with El Paso Corporation. We recorded the communication assets at El Paso Corporation’s book value of $23.3 million with the offset to partners’ capital.

 

As a result of the October 2003 exchange, we revised our estimate for the depreciable life of the Chaco plant from 19 to 30 years, the estimated remaining useful life of the Chaco plant. Depreciation expense will decrease approximately $0.5 million and $2.3 million on a quarter and annual basis.

 

Cameron Highway Oil Pipeline Company

 

Refer to Note 3 for a discussion related to our sale of a 50 percent interest in Cameron Highway Oil Pipeline.

 

San Juan Assets

 

In November 2002, we acquired from subsidiaries of El Paso Corporation, interests in assets we collectively refer to as the San Juan assets, which consist of the following:

 

    100 percent of El Paso Field Services’ San Juan Gathering and Processing Businesses, which include a natural gas gathering system and related compression facilities, the Rattlesnake Treating Plant, a 50-percent equity interest in Coyote Gas Treating, L.L.C. which owns the Coyote natural gas treating facility, and the remaining interests in the Chaco cryogenic natural gas processing plant we did not already own, all of which are located in the San Juan Basin of northwest New Mexico and southwestern Colorado;

 

    100 percent of the Typhoon Oil Pipeline assets located in the Deepwater Trend area of the Gulf of Mexico. Typhoon Oil was placed in service in July 2001 and provides transportation of oil produced from the Typhoon field for delivery to a platform in Green Canyon Block 19 with onshore access through various oil pipelines;

 

    100 percent of the Typhoon Gas Pipeline, which was placed in service in August 2001. Typhoon Gas is also located in the Deepwater Trend area of the Gulf of Mexico. The pipeline gathers natural gas from the Typhoon field for redelivery into El Paso Corporation’s ANR Patterson System; and

 

    100 percent of the Coastal Liquids Partners’ NGL Business, consisting of an integrated set of NGL assets that stretch from the Mexico border near McAllen, Texas, to Houston, Texas. This business includes a fractionation facility near Houston, Texas; a truck-loading terminal near McAllen, Texas, and leased underground NGL storage facilities.

 

We purchased the San Juan assets for $782 million, $764 million after adjustments for capital expenditures and actual working capital acquired. During 2003, the total purchase price and net assets acquired decreased $2.4 million due to post-closing purchase price adjustments related to natural gas imbalances, NGL in-kind reserves and well loss reserves. We financed the purchase of these assets with net proceeds from an offering of $200 million of 10  5 / 8 % Senior Subordinated Notes due 2012; borrowings of $237.5 million under our senior secured acquisition term loan; our issuance, to El Paso Corporation, of 10,937,500 of our Series C units valued at $32 per unit or $350 million; and currently available funds. We acquired the San Juan assets because they are strategically located in active supply development areas and are supported by long-term contracts that provide us with growing and reliable cash flows consistent with our stated growth strategy.

 

In connection with this acquisition, we entered into an agreement with El Paso Corporation under which El Paso Corporation would have been required, subject to specified conditions, to repurchase the Chaco plant from

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

us for $77 million in October 2021, at which time we would have had the right to lease the plant from them for a period of 10 years with the option to renew the lease annually thereafter. In October 2003, we released El Paso Corporation from that repurchase obligation in exchange for El Paso Corporation contributing communication assets to us.

 

As a result of our acquisition of the San Juan assets, our financial results from the operation of the Chaco plant are significantly different from our results prior to the purchase in the following ways:

 

    We no longer receive fixed fee revenue of $0.134/Dth for natural gas processed; rather, from a majority of our customers, we receive a processing fee of an in-kind portion of the NGL produced from the natural gas processed. We then sell these NGL and, accordingly, our processing revenues are affected by changes in the price of NGL.

 

    We no longer receive revenue for leasing the Chaco plant to El Paso Field Services.

 

    We no longer recognize amortization expense relating to our investment in processing agreement, which we terminated upon completing the acquisition. This decrease in amortization expense is offset by additional depreciation expense associated with the acquired assets.

 

In accordance with our procedures for evaluating and valuing material acquisitions with El Paso Corporation, our Audit and Conflicts Committee engaged independent financial advisors. Separate financial advisors delivered fairness opinions for the acquisition of the San Juan assets and the issuance of the Series C units. Based on these opinions, our Audit and Conflicts Committee and the full Board approved these transactions.

 

The following table summarizes our allocation of the fair values of the assets acquired and liabilities assumed at November 27, 2002. Our allocation among the assets acquired is based on the results of an independent third-party appraisal.

 

    

AT

NOVEMBER 27,

2002


     (IN THOUSANDS)

Note receivable

   $ 17,100

Property, plant and equipment

     763,696

Intangible assets

     470

Investment in unconsolidated affiliate

     2,500
    

Total assets acquired

     783,766
    

Imbalances payable

     17,403

Other current liabilities

     2,565
    

Total liabilities assumed

     19,968
    

Net assets acquired

   $ 763,798
    

 

The acquired intangible assets represent contractual rights we obtained under dedication and transportation agreements with producers which we are amortizing to expense over the life of the contracts of approximately 4 years. We recorded adjustments to the purchase price of approximately $18 million primarily for capital expenditures and actual working capital acquired.

 

Our consolidated financial statements include the results of operations of the San Juan assets from the November 27, 2002 purchase date. We have included the assets and operating results of the El Paso Field

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Services’ San Juan Gathering and Processing Businesses and the Typhoon Gas Pipeline in our natural gas pipelines and plants segment and the assets and operating results of the Typhoon Oil Pipeline and Coastal Liquids Partners’ NGL Business in our oil and NGL logistics segment from the purchase date. The following selected unaudited pro forma financial information presents our consolidated operating results for the years ended December 31, 2002 and 2001 as if we acquired the San Juan assets on January 1, 2001:

 

             2002        

           2001        

     (IN THOUSANDS, EXCEPT
PER UNIT AMOUNTS)

Operating revenues

   $ 627,191    $ 427,942

Income from continuing operations

   $ 88,902    $ 77,219

Income allocated to common unitholders from continuing operations

   $ 25,738    $ 16,687

Basic and diluted net income per unit from continuing operations

   $ 0.60    $ 0.43

 

The unaudited pro forma financial information presented above is not necessarily indicative of the results of operations we might have realized had the transaction been completed at the beginning of the earliest period presented, nor do they necessarily indicate our consolidated operating results for any future period.

 

EPN Holding Assets

 

In April 2002, we acquired, through a series of related transactions, from subsidiaries of El Paso Corporation the following midstream assets located in Texas and New Mexico, which we collectively refer to, for purposes of these financial statements, as the EPN Holding assets:

 

    The Waha natural gas gathering and treating system and the Carlsbad natural gas gathering system which are generally located in the Permian Basin region of Texas and New Mexico.

 

    A 50 percent undivided interest in the Channel Pipeline System, an intrastate natural gas transmission system located along the Gulf Coast of Texas.

 

    The TPC Offshore pipeline system, a collection of natural gas gathering and transmission assets located offshore of Matagorda Bay, Texas, including the Oyster Lake and MILSP Condensate Separation and Stabilization facilities and other undivided interests in smaller pipelines.

 

    GulfTerra Texas Pipeline, L.P. which owned, among other assets, (i) the GulfTerra Texas intrastate pipeline system, (ii) the TGP natural gas lateral pipelines, (iii) the leased natural gas storage facilities located in Wharton County, Texas generally known as the Wilson Storage facility, (iv) an 80 percent undivided interest in the East Texas 36 inch pipeline, (v) a 50 percent undivided interest in the West Texas 30 inch pipeline, (vi) a 50 percent undivided interest in the North Texas 36 inch pipeline, (vii) the McMullen County natural gas gathering system, (viii) the Hidalgo County natural gas gathering system, (ix) a 22 percent undivided interest in the Bethel-Howard pipeline, and (x) a 75 percent undivided interest in the Longhorn pipeline.

 

    El Paso Hub Services L.L.C. which owned certain contract rights and parcels of real property located in Texas.

 

    100 percent of the outstanding joint venture interest in Warwink Gathering and Treating Company which owned, among other assets, the Warwink natural gas gathering system located in the Permian Basin region of Texas and New Mexico.

 

In conjunction with the acquisition of the above assets, we obtained from another affiliate of El Paso Corporation, all of the equity interest in El Paso Indian Basin, L.P. which owned a 42.3 percent undivided, non-operating interest in the Indian Basin natural gas processing plant and treating facility located in southeastern New Mexico and the price risk management activities associated with the plant.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

We acquired the EPN Holding assets to provide us with a significant new source of cash flow, greater diversification of our midstream asset base and to provide new long term internal growth opportunities in the Texas intrastate market. We purchased the EPN Holding assets for $750 million, adjusted for the assumption of $15 million of net working capital obligations related to natural gas imbalances resulting in net consideration of $735 million comprised of the following:

 

    $420 million of cash;

 

    $119 million of assumed short-term indebtedness payable to El Paso Corporation, which we subsequently repaid;

 

    $6 million in common units; and

 

    $190 million in assets, comprised of our Prince TLP and our nine percent overriding royalty interest in the Prince field (see discussion below).

 

During 2003, the purchase price and net assets acquired increased $17.5 million due to post-closing purchase price adjustments related primarily to a reduction in natural gas imbalance payables assumed in the transaction.

 

We entered into a limited recourse credit agreement with a syndicate of commercial banks to finance substantially all of the cash consideration associated with this transaction. See Note 6 for additional discussion regarding the EPN Holding term credit facility.

 

The following table summarizes our allocation of the fair values of the assets acquired and liabilities assumed at April 8, 2002. Our allocation among the assets acquired is based on the results of an independent third-party appraisal.

 

    

AT APRIL 8,

2002


     (IN THOUSANDS)

Current assets

   $ 4,690

Property, plant and equipment

     780,648

Intangible assets

     3,500
    

Total assets acquired

     788,838
    

Current liabilities

     15,229

Environmental liabilities

     21,136
    

Total liabilities assumed

     36,365
    

Net assets acquired

   $ 752,473
    

 

The acquired intangible assets represent contractual rights we obtained under dedication and transportation agreements with producers which we will amortize to expense using the units-of-production method over the expected lives of the underlying reserves ranging from 26 to 45 years. Additionally, we assumed environmental liabilities of $21.1 million for estimated environmental remediation costs associated with the GulfTerra Texas intrastate pipeline assets as discussed in Note 11.

 

Our consolidated financial statements include the results of operations of the EPN Holding assets from the April 8, 2002 purchase date. We have included the assets and operating results of the Waha, Carlsbad and Warwink natural gas gathering systems; the Channel and TPC Offshore pipeline systems; and the GulfTerra Texas pipeline assets (excluding the Wilson Storage facility) in our natural gas pipelines and plants segment. Our 42.3 percent ownership interest in the assets and operating results of the Indian Basin plant are included in our oil and NGL

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

logistics segment and the Wilson storage facility assets and operating results are included in our natural gas storage segment. The following selected unaudited pro forma information depicts our consolidated results of operations for the years ended December 31, 2002 and 2001 as if we acquired the EPN Holding assets on January 1, 2001:

 

             2002        

           2001        

     (IN THOUSANDS, EXCEPT
PER UNIT AMOUNTS)

Operating revenues

   $ 540,154    $ 538,095

Income from continuing operations

   $ 114,517    $ 81,022

Income allocated to common unitholders from continuing operations

   $ 56,020    $ 38,874

Basic and diluted net income per unit from continuing operations

   $ 1.31    $ 1.13

 

The unaudited pro forma financial information presented above is not necessarily indicative of the results of operations we might have realized had the transaction been completed at the beginning of the earliest period presented, nor do they necessarily indicate our consolidated operating results for any future period.

 

Prince Assets

 

In connection with our April 2002 acquisition of the EPN Holding assets from El Paso Corporation, we sold our Prince tension leg platform (TLP) and our nine percent overriding royalty interest in the Prince Field to subsidiaries of El Paso Corporation. The results of operations for these assets have been accounted for as discontinued operations and have been excluded from continuing operations for all periods in our consolidated statements of income. Accordingly, the segment results in Note 15 reflect neither the results of operations for the Prince assets nor the related net assets held for sale. The Prince TLP was previously included in the platform services segment and related royalty interest was included in non-segment activity. Included in income from discontinued operations for the years ended December 31, 2002 and 2001 were revenues of $7.8 million and $8.8 million attributable to these disposed assets.

 

In April 2002, we sold the Prince assets for $190 million and recognized a gain on the sale of $0.4 million during 2002. In conjunction with this transaction, we repaid the related outstanding $95 million principal balance under our Argo term loan.

 

Deepwater Holdings L.L.C. and Chaco Transaction

 

In October 2001, we acquired the remaining 50 percent interest that we did not already own in Deepwater Holdings for approximately $81 million, consisting of $26 million cash and $55 million of assumed indebtedness, and at the acquisition date also repaid all of Deepwater Holdings’ $110 million of indebtedness. HIOS and East Breaks became indirect wholly-owned assets through this transaction. In a separate transaction, we acquired interests in the title holder of, and other interests in the Chaco cryogenic natural gas processing plant for $198.5 million. The total purchase price was composed of a payment of $77 million to acquire the plant from the bank group that provided the financing for the construction of the facility and a payment of $121.5 million to El Paso Field Services in connection with the execution of a 20-year fee-based processing agreement relating to the processing capacity of the Chaco plant and dedication of natural gas gathered by El Paso Field Services to the Chaco plant. Under the terms of the processing agreement, we received a fixed fee for each dekatherm of natural gas that we processed at the Chaco plant, and we bore all costs associated with the plant’s ownership and operations. El Paso Field Services personnel continued to operate the plant. In accordance with the original construction financing agreements, the Chaco plant was under an operating lease to El Paso Field Services. El Paso Field Services had the right to repurchase the Chaco plant at the end of the lease term in October 2002 for approximately $77 million. We funded both of these transactions by borrowing from our revolving credit facility. We accounted for these transactions as purchases and have assigned the purchase price to the net assets acquired based upon the estimated fair value of the net assets as of the acquisition date. The operating results associated

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

with Deepwater Holdings are included in earnings from unconsolidated affiliates for the periods prior to October 2001. We have included the operating results of Deepwater Holdings and the Chaco plant in our consolidated financial statements from the acquisition date.

 

Since the Chaco transaction was an asset acquisition, we have assigned the total purchase price to property, plant and equipment and investment in processing agreement. Since the Deepwater Holdings transaction was an acquisition of additional interests in a business, we are providing summary information related to the acquisition of Deepwater Holdings in the following table (in thousands):

 

Fair value of assets acquired

   $ 81,331  

Cash acquired

     5,386  

Fair value of liabilities assumed

     (60,917 )
    


Net cash paid

   $ 25,800  
    


 

In connection with our acquisition of the San Juan assets in November 2002, the original terms of the processing, lease and operating agreements between the Chaco plant and El Paso Field Services were terminated. The effect on our operation of the Chaco plant resulting from our acquisition of the San Juan assets is discussed above.

 

GTM Texas (formerly EPN Texas)

 

In February 2001, we acquired GTM Texas from a subsidiary of El Paso Corporation for $133 million. We funded the acquisition of these assets by borrowing from our revolving credit facility. These assets include more than 500 miles of NGL gathering and transportation pipelines. The NGL pipeline system gathers and transports unfractionated and fractionated products. We also acquired three fractionation plants with a capacity of approximately 96 MBbls/d. These plants fractionate NGL into ethane, propane, butane and natural gasoline products that are used by refineries and petrochemical plants along the Texas Gulf Coast. We accounted for the acquisition as a purchase and assigned the purchase price to the assets acquired based upon the estimated fair value of the assets as of the acquisition date. We have included the operating results of GTM Texas in our consolidated financial statements from the acquisition date.

 

The following selected unaudited pro forma information represents our consolidated results of operations on a pro forma basis for the year ended December 31, 2001, as if we acquired GTM Texas, the Chaco plant and the remaining 50 percent interest in Deepwater Holdings on January 1, 2001:

 

     2001

     (IN THOUSANDS, EXCEPT
PER UNIT AMOUNTS)

Operating revenues

   $ 269,681

Operating income

   $ 101,406

Net income allocated to limited partners

   $ 39,157

Basic and diluted net income per unit

   $ 1.14

 

Gulf of Mexico Assets

 

In accordance with an FTC order related to El Paso Corporation’s merger with The Coastal Corporation, we, along with Deepwater Holdings, agreed to sell several of our offshore Gulf of Mexico assets to third parties in January 2001. Total consideration received for these assets was approximately $163 million consisting of approximately $109 million for the assets we sold and approximately $54 million for the assets Deepwater Holdings sold. The offshore assets sold include interests in Stingray, UTOS, Nautilus, Manta Ray Offshore,

 

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Nemo, Tarpon, and the Green Canyon pipeline assets, as well as interests in two offshore platforms and one dehydration facility. We recognized net losses from the asset sales of approximately $12 million, and Deepwater Holdings recognized losses of approximately $21 million. Our share of Deepwater Holdings’ losses was approximately $14 million, which has been reflected in earnings from unconsolidated affiliates in the accompanying 2001 consolidated statement of income.

 

As additional consideration for the above transactions, El Paso Corporation agreed to make payments to us totaling $29 million. These payments were made in quarterly installments of $2.25 million for three years beginning in 2001 and we will receive the final payment of $2 million in the first quarter of 2004. From this additional consideration, we realized income of approximately $25 million in the first quarter of 2001, which has been reflected in other income in the accompanying 2001 consolidated statement of income.

 

3. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

 

We hold investments in unconsolidated affiliates which are accounted for using the equity method of accounting. As of December 31, 2003, the carrying amount of our equity investments exceeded the underlying equity in net assets by approximately $3.0 million, which is included in our oil and NGL logistics segment. With our adoption of SFAS No. 142 on January 1, 2002, we no longer amortize this excess amount, refer to Note 1, Summary of Significant Accounting Policies, Goodwill and Other Intangible Assets. Summarized financial information for these investments is as follows:

 

     AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2003

 
     COYOTE

   

DEEPWATER

GATEWAY(C)


   

CAMERON

HIGHWAY(C)


    POSEIDON

    TOTAL

 
     (IN THOUSANDS)  

END OF PERIOD OWNERSHIP INTEREST

     50 %     50 %     50 %     36 %        
    


 


 


 


       

OPERATING RESULTS DATA:

                                        

Operating revenues

   $ 7,200     $ —       $ —       $ 41,293          

Other income

     7       47       37       56          

Operating expenses

     (355 )     —         —         (3,694 )        

Depreciation

     (1,381 )     —         —         (8,316 )        

Other expenses

     (736 )     (31 )     (171 )     (6,313 )        
    


 


 


 


       

Net income (loss)

   $ 4,735     $ 16     $ (134 )   $ 23,026          
    


 


 


 


       

OUR SHARE:

                                        

Allocated income (loss)

   $ 2,368     $ 8     $ (67 )   $ 8,289          

Adjustments(a)

     9       (8 )     67       (191 )        
    


 


 


 


       

Earnings from unconsolidated affiliate

   $ 2,377     $ —       $ —       $ 8,098     $ 11,373 (b)
    


 


 


 


 


Allocated distributions

   $ 3,500     $ —       $ —       $ 8,640     $ 12,140  
    


 


 


 


 


FINANCIAL POSITION DATA:

                                        

Current assets

   $ 987     $ 8,271     $ 53,644     $ 98,937          

Noncurrent assets

     31,897       230,825       266,554       218,893          

Current liabilities

     34,784       18,294       26,332       91,146          

Noncurrent liabilities

     —         155,000       125,000       123,000          

(a) We recorded adjustments primarily for differences from estimated earnings reported in our Annual Report on our Form 10-K and actual earnings reported in the unaudited financial statements of our unconsolidated affiliates.

 

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(b) Total earnings from unconsolidated affiliates includes a $898 thousand gain associated with the sale of our interest in Copper Eagle.
(c) Cameron Highway Oil Pipeline Company and Deepwater Gateway, L.L.C. are development stage companies; therefore there are no operating revenues or operating expenses to provide operational results. Since their formations, they have incurred organizational expenses and received interest income.

 

Cameron Highway. In June 2003, we formed Cameron Highway Oil Pipeline Company and contributed to this newly formed company the $458 million Cameron Highway oil pipeline system construction project. Cameron Highway is responsible for building and operating the pipeline, which is scheduled for completion during the fourth quarter of 2004. We entered into producer agreements with three major anchor producers, BP Exploration & Production Company, BHP Billiton Petroleum (Deepwater), Inc., and Union Oil Company of California, which agreements were assigned to and assumed by Cameron Highway. The producer agreements require construction of the 390-mile Cameron Highway oil pipeline.

 

In July 2003, we sold a 50 percent interest in Cameron Highway to Valero Energy Corporation for $86 million, forming a joint venture with Valero. Valero paid us approximately $70 million at closing, including $51 million representing 50 percent of the capital investment expended through that date for the pipeline project. In July 2003, we recognized $19 million as a gain from the sale of long-lived assets. In addition, Valero will pay us $5 million once the system is completed and another $11 million by the end of 2006. We expect to reflect the receipts of these additional amounts in the periods received as gains from the sale of long-lived assets in our statement of income. In connection with the formation of the Cameron Highway joint venture, Valero agreed to pay their proportionate share of pipeline construction costs that exceed Cameron Highway’s capital resources, including the initial equity contributions and proceeds from Cameron Highway’s project loan facility.

 

The Cameron Highway oil pipeline system project is expected to be funded with 37 percent equity, or $169 million through capital contributions from us and Valero, the two Cameron Highway partners, which contributions have already been made, and 63 percent debt through a $325 million project loan facility, consisting of a $225 million construction loan and $100 million of senior secured notes. See Note 6 for additional discussion of the project loan facility. As of December 31, 2003, Cameron Highway has spent approximately $256 million (of which $85 million constituted equity contributions by us) related to this pipeline, which is in the construction stage. We and Valero are obligated to make additional capital contributions to Cameron Highway if and to the extent that the construction costs for the pipeline exceed Cameron Highway’s capital resources, including initial equity contributions and proceeds from Cameron Highway’s project loan facility.

 

Deepwater Gateway. As of December 31, 2003, we have contributed $33 million, as our 50 percent share, to Deepwater Gateway, which amount satisfies our initial equity funding requirement related to the Marco Polo TLP. We expect that the remaining costs associated with the Marco Polo TLP will be funded through the $155 million project finance loan and Deepwater Gateway’s members’ contingent equity obligations (of which our share is $14 million). This project finance loan will mature in July 2004 unless construction is completed before that time and Deepwater Gateway meets other specified conditions, in which case the project finance loan will convert into a term loan with a final maturity date of July 2009. The loan agreement requires Deepwater Gateway to maintain a debt service reserve equal to six months’ interest. Other than that debt service reserve and any other reserve amounts agreed upon by more than 66.7 percent majority interest of Deepwater Gateway’s members, Deepwater Gateway will (after the project finance loan is either repaid or converted into a term loan) distribute any available cash to its members quarterly. Deepwater Gateway is not currently generating income or cash flow. Deepwater Gateway is managed by a management committee consisting of representative from each of its members.

 

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Front Runner Oil Pipeline. In September 2003, we announced that Poseidon, our 36 percent owned joint venture, entered into an agreement for the purchase and sale of crude oil from the Front Runner Field. Poseidon will construct, own and operate the $28 million project, which will connect the Front Runner platform with Poseidon’s existing system at Ship Shoal Block 332. The new 36-mile, 14-inch pipeline is expected to be operational by the third quarter of 2004 and have a capacity of 65 MBbls/d. As Poseidon expects to fund Front Runner’s capital expenditures from its operating cash flow and from its revolving credit facility, we do not expect to receive distributions from Poseidon until the Front Runner oil pipeline is completed.

 

     AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2002

       COYOTE(A)  

      POSEIDON  

   

DEEPWATER

  GATEWAY(B)  


      TOTAL  

     (IN THOUSANDS)

END OF PERIOD OWNERSHIP INTEREST

     50 %     36 %     50 %      
    


 


 


     

OPERATING RESULTS DATA:

                              

Operating revenues

   $ 635     $ 54,261     $ —          

Other income

     2       26,695       20        

Operating expenses

     (38 )     (4,691 )     —          

Depreciation

     (110 )     (8,356 )     —          

Other expenses

     (75 )     (6,923 )     (234 )      
    


 


 


     

Net income (loss)

   $ 414     $ 60,986     $ (214 )      
    


 


 


     

OUR SHARE:

                              

Allocated income (loss)

   $ 207     $ 21,955     $ (107 )      

Adjustments(c)

     (13 )     (8,510 )     107        
    


 


 


     

Earnings from unconsolidated affiliate

   $ 194     $ 13,445     $ —       $ 13,639
    


 


 


 

Allocated distributions

   $ 2,000     $ 15,804     $ —       $ 17,804
    


 


 


 

FINANCIAL POSITION DATA:

                              

Current assets

   $ 1,575     $ 152,784     $ 10,745        

Noncurrent assets

     33,349       218,463       110,309        

Current liabilities

     34,559       119,974       28,268        

Noncurrent liabilities

     —         148,000       27,000        

(a) We acquired an interest in Coyote Gas Treating, L.L.C. in November 2002 as part of the San Juan assets acquisition.
(b) In June 2002, we formed Deepwater Gateway, L.L.C., a 50/50 joint venture with Cal Dive International, Inc., to construct and install the Marco Polo TLP. Also in August 2002, Deepwater Gateway obtained a project finance loan to fund a substantial portion of the cost to construct the Marco Polo TLP. For further discussion of this project loan, see Note 6, Financing Transactions. Deepwater Gateway, L.L.C. is a development stage company; therefore there are no operating revenues or operating expenses to provide operational results. Since Deepwater Gateway’s formation in 2002, it has incurred organizational expenses and received interest income.
(c) We recorded adjustments primarily for differences from estimated year end earnings reported in our Annual Report on our Form 10-K and actual earnings recorded in the audited annual reports of our unconsolidated affiliates. The adjustment for Poseidon primarily represents the receipt of proceeds from a favorable litigation related to the January 2000 pipeline rupture.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

     AS OF OR FOR THE YEAR ENDED DECEMBER 31, 2001

    

DEEPWATER

HOLDINGS(A)


    POSEIDON

   

DIVESTED

INVESTMENTS(B)


    OTHER(C)

    TOTAL

     (IN THOUSANDS)

END OF PERIOD OWNERSHIP INTEREST

     100 %     36 %     —         50 %      
    


 


 


 


     

OPERATING RESULTS DATA:

                                      

Operating revenues

   $ 40,933     $ 70,401     $ 1,982     $ 145        

Other income (loss)

     —         394       (85 )     —          

Operating expenses

     (16,740 )     (1,586 )     (590 )     (73 )      

Depreciation

     (8,899 )     (10,552 )     (953 )     —          

Other (expenses) income

     (5,868 )     (7,668 )     222       (22 )      

Loss on sale of assets

     (21,453 )     —         —         —          
    


 


 


 


     

Net income (loss)

   $ (12,027 )   $ 50,989     $ 576     $ 50        
    


 


 


 


     

OUR SHARE:

                                      

Allocated income (loss)(d)

   $ (9,925 )   $ 18,356     $ 148     $ 25        

Adjustments(e)

     —         (146 )     (9 )     —          
    


 


 


 


     

Earnings (loss) from unconsolidated affiliates

   $ (9,925 )   $ 18,210     $ 139     $ 25     $ 8,449
    


 


 


 


 

Allocated distributions

   $ 12,850     $ 22,212     $ —       $ —       $ 35,062
    


 


 


 


 

FINANCIAL POSITION DATA:

                                      

Current assets

           $ 91,367             $ 177        

Noncurrent assets

             226,570               —          

Current liabilities

             80,365               33        

Noncurrent liabilities

             150,000               —          

(a) In January 2001, Deepwater Holdings sold its Stingray and West Cameron subsidiaries. Deepwater Holdings sold its interest in its UTOS subsidiary in April 2001. In October 2001, we acquired the remaining 50 percent of Deepwater Holdings and as a result of this transaction, from the acquisition date Deepwater Holdings is consolidated in our financial statements. The information presented for Deepwater Holdings as an equity investment is through October 18, 2001.
(b) Divested Investments contains Manta Ray Offshore Gathering Company, L.L.C. and Nautilus Pipeline Company L.L.C. In January 2001, we sold our 25.67 percent interest in Manta Ray Offshore and our 25.67 percent interest in Nautilus.
(c) Through October 2001 this company processed gas for Deepwater Holdings’ Stingray subsidiary. This agreement was terminated in October 2001, and as of this date there are no operations related to this investment.
(d) The income (loss) from Deepwater Holdings is not allocated proportionately with our ownership percentage because the capital contributed by us was a larger amount of the total capital at the time of formation. Therefore, we were allocated a larger amount of amortization of Deepwater Holdings’ excess purchase price of its investments. Also, we were allocated a larger portion of Deepwater Holdings’ $21 million loss incurred in 2001 due to the sale of Stingray, UTOS, and the West Cameron dehydration facility. Our total share of the losses relating to these sales was approximately $14 million.
(e) We recorded adjustments primarily for differences from estimated year end earnings reported in our Annual Report on Form 10-K and actual earnings reported in the audited annual reports of our unconsolidated affiliates.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

4. PROPERTY, PLANT AND EQUIPMENT

 

Our property, plant and equipment consisted of the following:

 

     DECEMBER 31,

     2003

   2002

     (IN THOUSANDS)

Property, plant and equipment, at cost(1)

             

Pipelines

   $ 2,487,102    $ 2,317,503

Platforms and facilities

     121,105      128,582

Processing plants

     305,904      300,897

Oil and natural gas properties

     131,100      127,975

Storage facilities

     337,535      331,562

Construction work-in-progress

     383,640      177,964
    

  

       3,766,386      3,384,483

Less accumulated depreciation, depletion and amortization

     871,894      659,545
    

  

Total property, plant and equipment, net

   $ 2,894,492    $ 2,724,938
    

  


(1) Includes leasehold acquisition costs with an unamortized balance of $3.2 million and $4.1 million at December 31, 2003 and 2002. One interpretation being considered relative to SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Intangible Assets is that oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves for both undeveloped and developed leaseholds should be classified separately from oil and gas properties, as intangible assets on our consolidated balance sheets. We will continue to include these costs in property, plant, and equipment until further guidance is provided.

 

Due to the sale of our interest in the Manta Ray Offshore system in January 2001, we lost a primary connecting point to our Manta Ray pipeline. As a result, we abandoned the Manta Ray pipeline and recorded an impairment of approximately $3.9 million in the first quarter of 2001 which is reflected in the natural gas pipelines and plants segment.

 

5. INVESTMENT IN PROCESSING AGREEMENT

 

As part of our October 2001 Chaco transaction, we paid $121.5 million to El Paso Field Services for a 20-year fee-based processing agreement. The processing agreement was being amortized on a straight-line basis over the life of the agreement and we recorded amortization expense of $5.6 million in 2002 and $1.5 million in 2001 related to this asset. As a result of the San Juan acquisition in November 2002, we now own the gathering system and related facilities previously owned by El Paso Field Services, including the rights of El Paso Field Services under the arrangements relating to the Chaco plant. As part of the San Juan acquisition, the processing agreement was terminated.

 

6. FINANCING TRANSACTIONS

 

CREDIT FACILITY

 

Our credit facility consists of two parts: the revolving credit facility maturing in 2006 and a senior secured term loan maturing in 2008. Our credit facility is guaranteed by us and all of our subsidiaries, except for our unrestricted subsidiaries, as detailed in Note 16, and are collateralized with substantially all of our assets (excluding the assets of our unrestricted subsidiaries). The interest rates we are charged on our credit facility are

 

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determined at our option using one of two indices that include (i) a variable base rate (equal to the greater of the prime rate as determined by JPMorgan Chase Bank, the federal funds rate plus 0.5% or the Certificate of Deposit (CD) rate as determined by JPMorgan Chase Bank increased by 1.00%); or (ii) LIBOR. The interest rate we are charged is contingent upon our leverage ratio, as defined in our credit facility, and ratings we are assigned by S&P or Moody’s. The interest we are charged would increase by 0.25% if the credit ratings on our senior secured credit facility decrease or our leverage ratio decreases, or, alternatively, would decrease by 0.25% if these ratings are increased or our leverage ratio improves. Additionally, we pay commitment fees on the unused portion of our revolving credit facility at rates that vary from 0.30% to 0.50%.

 

Our credit facility contains covenants that include restrictions on our and our subsidiaries’ ability to incur additional indebtedness or liens, sell assets, make loans or investments, acquire or be acquired by other companies and amend some of our contracts, as well as requiring maintenance of certain financial ratios. Failure to comply with the provisions of any of these covenants could result in acceleration of our debt and other financial obligations and that of our subsidiaries and restrict our ability to make distributions to our unitholders. The financial covenants associated with our credit facility are as follows:

 

(a) The ratio of consolidated EBITDA, as defined in our credit agreements, to consolidated interest expense cannot be less than 2.0 to 1.0;

 

(b) The ratio of consolidated total senior indebtedness on the last day of any fiscal quarter to the consolidated EBITDA for the four quarters ending on the last day of the current quarter cannot exceed 3.25 to 1.0; and

 

(c) The ratio of our consolidated total indebtedness on the last day of any fiscal quarter to the consolidated EBITDA for the four quarters ending on the last day of the current quarter cannot exceed 5.25 to 1.0.

 

Among other things, our credit agreement includes as an event of default a change of control, defined as the failure of El Paso Corporation and its subsidiaries to no longer own at least 50 percent of our general partner. We are in compliance with the financial ratios and covenants contained in each of our credit facilities at December 31, 2003.

 

Revolving Credit Facility

 

In September 2003, we renewed our revolving credit facility to, among other things, expand the credit available from $600 million to $700 million and extend the maturity from May 2004 to September 2006.

 

At December 31, 2003, we had $382 million outstanding under our revolving credit facility at an average interest rate of 3.17%. We may elect that all or a portion of the revolving credit facility bear interest at either the variable rate described above increased by 1.0% or LIBOR increased by 2.0%. The total amount available to us at December 31, 2003, under this facility was $318 million.

 

Senior Secured Term Loan

 

In December 2003, we refinanced the term loan portion of our credit facility to provide greater financial flexibility by, among other things, expanding the existing term component from $160 million to $300 million, extending the maturity from October 2007 to December 2008, reducing the semi-annual payments from $2.5 million to $1.5 million and reducing the interest rate we are charged by 1.25%. We used the proceeds from the term loan to repay the $155 million outstanding under the initial term loan and to temporarily reduce amounts outstanding under our revolving credit facility. We charged $2.8 million to interest and debt expense in December 2003 to write-off unamortized debt issuance costs associated with the initial term loan.

 

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The senior secured term loan is payable in semi-annual installments of $1.5 million in June and December of each year for the first nine installments and the remaining balance at maturity in December 2008. We may elect that all or a portion of the senior secured term loan bear interest at either 1.25% over the variable base rate discussed above; or LIBOR increased by 2.25%. As of December 31, 2003, we had $300 million outstanding with an average interest rate of 3.42%. GulfTerra Holding Term Credit Facility (formerly EPN Holding Term Credit Facility)

 

In connection with our acquisition of the EPN Holding assets from El Paso Corporation in April 2002, EPN Holding entered into a $560 million term credit facility with a group of commercial banks. The term credit facility provided a term loan (the GulfTerra Holding term loan) of $535 million to finance the acquisition of the EPN Holding assets, and a revolving credit facility (the GulfTerra Holding revolving credit facility) of up to $25 million to finance EPN Holding’s working capital. At the time of its acquisition, EPN Holding borrowed $535 million ($531 million, net of issuance costs) under this term loan and had $25 million available under the GulfTerra Holding revolving credit facility. We used net proceeds of approximately $149 million from our April 2002 common unit offering, $0.6 million contributed by our general partner to maintain its one percent capital account balance and $225 million of the net proceeds from our May 2002 offering of 8  1 / 2 % Senior Subordinated Notes to reduce indebtedness under the term loan. In July 2003, we repaid the remaining $160 million balance of this term credit facility with proceeds from our issuance of $250 million 6  1 / 4 % senior notes due 2010. We recognized a loss of $1.2 million related to the write-off of unamortized debt issuance costs in connection with our repayment of this facility.

 

Senior Secured Acquisition Term Loan

 

As part of our November 2002 San Juan assets acquisition, we entered into a $237.5 million senior secured acquisition term loan to fund a portion of the purchase price. We repaid this senior secured acquisition term loan in March 2003 with proceeds from our issuance of $300 million 8  1 / 2 % senior subordinated notes due 2010. We recognized a loss of $3.8 million related to the write-off of unamortized debt issuance costs in connection with our repayment of this facility. From the issuance of the senior secured acquisition term loan in November 2002 to its repayment date, the interest rates on our revolving credit facility and GulfTerra Holding term credit facility were 2.25% over the variable base rate described above or LIBOR increased by 3.50%.

 

Argo Term Loan

 

This loan with a balance of $95 million, including current maturities, at December 31, 2001, was repaid in full in April 2002, in connection with the EPN Holding assets acquisition.

 

SENIOR NOTES

 

In July 2003, we issued $250 million in aggregate principal amount of 6  1 / 4 % senior notes due June 2010. We used the proceeds of approximately $245.1 million, net of issuance costs, to repay $160 million of indebtedness under the GulfTerra Holding term credit facility and to temporarily repay $85.1 million of the balance outstanding under our revolving credit facility. The interest on our senior notes is payable semi-annually in June and December with the principal maturing in June 2010. Our senior notes are unsecured obligations that rank senior to all our existing and future subordinated debt and equally with all of our existing and future senior debt, although they are effectively junior in right of payment to all of our existing and future senior secured debt to the extent of the collateral securing that debt. Our senior notes are guaranteed by us and all of our subsidiaries, except for our unrestricted subsidiaries.

 

We may redeem some or all of our senior notes, at our option, at any time with at least 30 days notice at a price equal to the greater of (1) 100 percent of the principal amount plus accrued interest, or (2) the sum of the present value of the remaining scheduled payments plus accrued interest.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

SENIOR SUBORDINATED NOTES

 

Each issue of our senior subordinated notes is subordinated in right of payment to all of our existing and future senior debt, including our existing credit facility and the senior notes we issued in July 2003.

 

In March 2003, we issued $300 million in aggregate principal amount of 8  1 / 2 % senior subordinated notes. The interest on these notes is payable semi-annually in June and December, and the notes mature in June 2010. We used the proceeds of approximately $293.5 million, net of issuance costs, to repay $237.5 million of indebtedness under our senior secured acquisition term loan and to temporarily repay $55.5 million of the balance outstanding under our revolving credit facility. We may, at our option, prior to June 1, 2006, redeem up to 33 percent of the originally issued aggregate principal amount of these notes at a redemption price of 108.50 percent of the principal amount, and in December 2003, we redeemed $45 million under this provision (see discussion below). We may redeem all or part of the remainder of these notes at any time on or after June 1, 2007. The redemption price on that date is 104.25 percent of the principal amount, declining annually until it reaches 100 percent of the principal amount.

 

In November 2002, we issued $200 million in aggregate principal amount of 10  5 / 8 % Senior Subordinated Notes. The interest on these notes is payable semi-annually in June and December, and mature in December 2012. These notes were issued for $198 million, net of discount of $1.5 million to yield 10.75% (proceeds of $194 million, net of issuance costs) which we used to fund a portion of the acquisition of the San Juan assets. We may, at our option, prior to December 1, 2005, redeem up to 33 percent of the originally issued aggregate principal amount of the notes at a redemption price of 110.625%, and in December 2003, we redeemed $66 million under this provision (see discussion below). On or after December 1, 2007, we may redeem all or part of the remainder of these notes at 105.313% of the principal amount.

 

In May 2002, we issued $230 million in aggregate principal amount of 8  1 / 2 % Senior Subordinated Notes. The interest on these notes is payable semi-annually in June and December, and mature June 2011. The Senior Subordinated Notes were issued for $234.6 million (proceeds of approximately $230 million, net of issuance costs). We used proceeds of $225 million to reduce indebtedness under our EPN Holding term credit facility and the remainder for general partnership purposes. We may, at our option, prior to June 1, 2004, redeem up to 33 percent of the originally issued aggregate principal amount of the senior subordinated notes due June 2011, at a redemption price of 108.500%, and in December 2003, we redeemed $75.9 million under this provision (see discussion below). On or after June 1, 2006, we may redeem all or part of the remainder of these notes at 104.250% of the principal amount.

 

In May 2001, we issued $250 million in aggregate principal amount of 8  1 / 2 % Senior Subordinated Notes. The interest on these notes is payable semi-annually in June and December, and mature in June 2011. Proceeds of approximately $243 million, net of issuance costs, were used to reduce indebtedness under our revolving credit facility. We may, at our option, prior to June 1, 2004, redeem up to 33 percent of the originally issued aggregate principal amount of the senior subordinated notes due June 2011, at a redemption price of 108.500%, and in December 2003, we redeemed $82.5 million under this provision (see discussion below). On or after June 1, 2006, we may redeem all or part of the remainder of these notes at 104.250% of the principal amount.

 

In May 1999, we issued $175 million in aggregate principal amount of 10  3 / 8 % Senior Subordinated Notes. The interest on these notes is payable semi-annually in June and December, and mature in June 2009. Proceeds of approximately $169 million, net of issuance costs, were used to reduce indebtedness under our revolving credit facility. On or after June 1, 2004, we may redeem all or part of these notes at 105.188% of the principal amount.

 

Our subsidiaries, except GulfTerra Energy Partners Finance Corporation and our unrestricted subsidiaries, have guaranteed our obligations under the senior notes and all of the issuances of senior subordinated notes

 

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described above. In addition, we could be required to repurchase the senior notes and senior subordinated notes if certain circumstances relating to change of control or asset dispositions exist.

 

In July 2003, to achieve a better mix of fixed rate debt and variable rate debt, we entered into an eight-year interest rate swap agreement to provide for a floating interest rate on $250 million of our 8  1 / 2 % senior subordinated notes due 2011. With this swap agreement, we will pay the counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was 1.55% at December 31, 2003) and receive a fixed rate of 8  1 / 2 %. We are accounting for this derivative as a fair value hedge under SFAS No. 133. At December 31, 2003, the fair value of the swap was a liability, included in non-current liabilities, of approximately $7.4 million. The fair value of the hedged debt decreased by the same amount.

 

In December 2003, we used a portion of the net proceeds from our October 2003 equity offerings to redeem approximately $269.4 million in principal amount of our senior subordinated notes. The terms of our indentures allow us to use proceeds from an equity offering, within a 90 day period after the offering, to redeem up to 33 percent of the principal during the first three years the notes are outstanding. We incurred additional costs totaling $29.1 million resulting from the payment of the redemption premiums and the write-off of unamortized debt issuance costs, premiums and discounts. We accounted for these costs as an expense during the fourth quarter of 2003 in accordance with the provisions of SFAS No. 145.

 

In March 2004, we gave notice to exercise our right, under the terms of our senior subordinated notes’ indentures, to repay, at a premium, approximately $39.1 million in principal amount of those senior subordinated notes. The indentures provide that, within 90 days of an equity offering, we can call up to 33 percent of the original face amount at a premium. The amount we can repay is limited to the net proceeds of the offering. We will recognize additional costs totaling $4.1 million resulting from the payment of the redemption premiums and the writeoff of unamortized debt issuance costs. We will account for these costs as an expense during the second quarter of 2004 in accordance with the provisions of SFAS No. 145.

 

RESTRICTIVE PROVISIONS OF SENIOR AND SENIOR SUBORDINATED NOTES

 

Our senior and senior subordinated notes include provisions that, among other things, restrict our ability and the ability of our subsidiaries (excluding our unrestricted subsidiaries) to incur additional indebtedness or liens, sell assets, make loans or investments, acquire or be acquired by other companies, and enter into sale and lease-back transactions, as well as requiring maintenance of certain financial ratios. Failure to comply with the provisions of these covenants could result in acceleration of our debt and other financial obligations and that of our subsidiaries in addition to restricting our ability to make distributions to our unitholders. Many restrictive covenants associated with our senior notes will effectively be removed following a period of 90 consecutive days during which they are rated Baa3 or higher by Moody’s or BBB- or higher by S&P, and some of the more restrictive covenants associated with some (but not all) of our senior subordinated notes will be suspended should they be similarly rated.

 

OTHER CREDIT FACILITIES

 

Poseidon

 

As of December 31, 2003, Poseidon Oil Pipeline Company, L.L.C., an unconsolidated affiliate in which we have a 36 percent joint venture ownership interest, was party to a $185 million credit agreement under which it had $123 million outstanding at December 31, 2003.

 

In January 2004, Poseidon amended its credit agreement and decreased the availability to $170 million. The amended facility matures in January 2008. The outstanding balance from the previous facility was transferred to the new facility.

 

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In January 2002, Poseidon entered into a two-year interest rate swap agreement to fix the variable LIBOR based interest rate on $75 million of the $123 million outstanding under its credit facility at 3.49% through January 2004. Poseidon, under its credit facility, currently pays an additional 1.25% over the LIBOR rate resulting in an effective interest rate of 4.74% on the hedged notional amount. The interest rates Poseidon is charged on balances outstanding under its credit facility are dependent on its leverage ratio as defined in the Poseidon credit facility. Poseidon’s interest rate at December 31, 2003 was LIBOR plus 1.25% for Eurodollar loans and a variable base rate equal to the greater of the prime rate or 0.50% plus the federal funds rate (as those terms are defined in the Poseidon credit agreement) plus 0.25% for Base Rate loans. As of December 31, 2003, the remaining $48 million was at an average interest rate of 2.46%.

 

Under its amended credit facility, based on Poseidon’s leverage ratio for the year ended December 31, 2003, Poseidon’s interest rate is LIBOR plus 2.00% for Eurodollar loans and a variable base rate equal to the greater of the prime rate or 0.50% plus the federal funds rate (as those terms are defined in the Poseidon credit agreement) plus 1.00% for Base Rate loans. Poseidon’s interest rates will decrease by 0.25% if their leverage ratio declines to 3.00 to 1.00 or less, by 0.50% if their leverage ratio declines to 2.00 to 1.00 or less, or by 0.625% if their leverage ratio declines to 1.00 to 1.00 or less. Additionally, Poseidon pays commitment fees on the unused portion of the credit facility at rates that vary from 0.25% to 0.375%. This credit agreement requires Poseidon to maintain a debt service reserve equal to two times the previous quarters’ interest.

 

Poseidon’s credit agreement contains covenants such as restrictions on debt levels, restrictions on liens collateralizing debt and guarantees, restrictions on mergers and on the sales of assets and dividend restrictions. A breach of any of these covenants could result in acceleration of Poseidon’s debt and other financial obligations.

 

Under the Poseidon $170 million revolving credit facility, the financial debt covenants are:

 

(a) Poseidon must maintain consolidated tangible net worth in an amount not less than $75 million plus 100% of the net cash proceeds from the issuance by Poseidon of equity securities of any kind;

 

(b) the ratio of Poseidon’s EBITDA, as defined in Poseidon’s credit agreement, to interest expense paid or accrued during the four quarters ending on the last day of the current quarter must be at least 2.50 to 1.00; and

 

(c) the ratio of total indebtedness of Poseidon to EBITDA for the four quarters ending on the last day of the current quarter shall not exceed 4.50 to 1.00 in 2004, 3.50 to 1.00 in 2005 and 3.00 to 1.00 thereafter.

 

Poseidon was in compliance with the above covenants and the covenants under its previous facility as of December 31, 2003.

 

Deepwater Gateway

 

In August 2002, Deepwater Gateway, our joint venture that is constructing the Marco Polo TLP, obtained a $155 million project finance loan from a group of commercial lenders to finance a substantial portion of the cost to construct the Marco Polo TLP and related facilities. Deepwater Gateway may elect that all or a portion of the project finance loan bear interest at either (i) LIBOR plus 1.75% or (ii) an alternate base rate (equal to the greater of the prime rate, the base CD rate plus 1% or the federal funds rate plus 0.5%, as those terms are defined in the project finance loan agreement) plus 0.75%. Deepwater Gateway must also pay commitment fees of 0.375% per year on the unused portion of the project finance loan. The loan is collateralized by substantially all of Deepwater Gateway’s assets. If Deepwater Gateway defaults on its payment obligations under the project finance loan, we would be required to pay to the lenders all distributions we or any of our subsidiaries have received from Deepwater Gateway up to $22.5 million. As of December 31, 2003, Deepwater Gateway had $155 million outstanding under the project finance loan at an average interest rate of 2.94% and had not paid us or any of our subsidiaries any distributions.

 

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This project finance loan will mature in July 2004 unless construction is completed before that time and Deepwater Gateway meets other specified conditions, in which case the project finance loan will convert into a term loan with a final maturity date of July 2009. Upon conversion of the project finance loan to a term loan, Deepwater Gateway will be required to maintain a debt service reserve of not less than the projected principal, interest and fees due on the term loan for the immediately succeeding six month period. In addition, Deepwater Gateway is prohibited from making distributions until the project finance loan has been repaid or is converted.

 

Cameron Highway

 

Cameron Highway Oil Pipeline Company (Cameron Highway), an unconsolidated affiliate in which we have a 50 percent joint venture ownership interest (See Note 3 for additional discussion relating to the formation of Cameron Highway), entered into a $325 million project loan facility, consisting of a $225 million construction loan and $100 million of senior secured notes, each of which fund proportionately as construction costs are incurred.

 

The $225 million construction loan bears interest at Cameron Highway’s option at each borrowing at either (i) 2.00% over the variable base rate (equal to the greater of the prime rate as determined by JPMorgan Chase Bank, the federal funds rate plus 0.5% or the Certificate of Deposit (CD) rate as determined by JPMorgan Chase Bank increased by 1.00%); or (ii) 3.00% over LIBOR. Upon completion of the construction, the construction loan will convert to a term loan maturing July 2008, subject to the terms of the loan agreement. At the end of the first quarter following the first anniversary of the conversion into a term loan, Cameron Highway will be required to make quarterly principal payments of $8.125 million, with the remaining unpaid principal amount payable on the maturity date. If the construction loan fails to convert into a term loan by December 31, 2006, the construction loan and senior secured notes become fully due and payable. At December 31, 2003, Cameron Highway had $69 million outstanding under the construction loan at an average interest rate of 4.21%.

 

The interest rate on Cameron Highway’s senior secured notes is 3.25% over the rate on 10-year U.S. Treasury securities. Principal payments of $4 million are due quarterly from September 2008 through December 2011, $6 million each from March 2012 through December 2012, and $5 million each from March 2013 through the principal maturity date of December 2013. At December 31, 2003, Cameron Highway had $56 million outstanding under the notes at an average interest rate of 7.38%.

 

Under the terms of its project loan facility, Cameron Highway must pay each of the lenders and the senior secured noteholders commitment fees of 0.5% per year on any unused portion of such lender’s or noteholder’s committed funds. The project loan facility as a whole is collateralized by (1) substantially all of Cameron Highway’s assets, including, upon conversion, a debt service reserve capital account, and (2) all of the equity interest in Cameron Highway. Other than the pledge of our equity interest and our construction obligations under the relevant producer agreements, as discussed in Note 3, the debt is non-recourse to us. The construction loan and senior secured notes prohibit Cameron Highway from making distributions to us until the construction loan is converted into a term loan and Cameron Highway meets certain financial requirements.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

DEBT MATURITY TABLE

 

Aggregate maturities of the principal amounts of long-term debt and other financing obligations for the next 5 years and in total thereafter are as follows (in thousands):

 

    2004

   $ 3,000

    2005

     3,000

    2006

     385,000

    2007

     3,000

    2008

     288,000

Thereafter

     1,135,600
    

Total long-term debt and other financing obligations, including current maturities

   $ 1,817,600
    

 

INTEREST AND DEBT EXPENSE

 

We recognized the interest cost incurred in connection with our financing transactions as follows for each of the years ended December 31:

 

     2003

    2002

    2001

 
     (IN THOUSANDS)  

Interest expense incurred

   $ 140,282     $ 87,522     $ 54,885  

Interest capitalized

     (12,452 )     (5,571 )     (11,755 )
    


 


 


Net interest expense

     127,830       81,951       43,130  

Less: Interest expense on discontinued operations

     —         891       1,588  
    


 


 


Net interest expense on continuing operations

   $ 127,830     $ 81,060     $ 41,542  
    


 


 


 

LOSS DUE TO EARLY REDEMPTIONS OF DEBT

 

We recognized losses associated with early redemptions of debt as follows for each of the years ended December 31:

 

     2003

   2002

     (IN THOUSANDS)

Loss due to payment of redemption premiums

   $ 24,302    $ —  

Loss due to write-off of unamortized debt issuance costs, premiums and discounts

     12,544      2,434
    

  

     $ 36,846    $ 2,434
    

  

 

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7. FINANCIAL INSTRUMENTS

 

Fair Value of Financial Instruments

 

The carrying amounts and estimated fair values of our financial instruments at December 31 are as follows:

 

     2003

   2002

    

CARRYING

AMOUNT


   FAIR VALUE

  

CARRYING

AMOUNT


   FAIR VALUE

     (IN MILLIONS)

Liabilities:

                           

Revolving credit facility

   $ 382.0    $ 382.0    $ 491.0    $ 491.0

GulfTerra Holding term credit facility

     —        —        160.0      160.0

Senior secured term loan

     300.0      300.0      160.0      160.0

Senior secured acquisition term loan

     —        —        237.5      237.5

10  3 / 8 % senior subordinated notes

     175.0      189.9      175.0      186.4

8  1 / 2 % senior subordinated notes(1)

     167.5      188.4      250.0      233.1

8  1 / 2 % senior subordinated notes(1)

     156.6      173.4      234.3      214.5

10  5 / 8 % senior subordinated notes

     133.1      165.5      198.5      205.5

8  1 / 2 % senior subordinated notes

     255.0      290.7      —        —  

6  1 / 4 % senior notes

     250.0      262.5      —        —  

Non-trading derivative instruments

                           

Commodity swap and forward contracts

   $ 9.0    $ 9.0    $ 4.7    $ 4.7

Interest rate swap

     7.4      7.4      —        —  

(1) Excludes market value of interest rate swap, see interest rate swap discussion below.

 

The notional amounts and terms of the financial instruments held for purposes other than trading were as follows at December 31:

 

     2003

   2002

     NOTIONAL
VOLUME


   MAXIMUM
TERM IN YEARS


   NOTIONAL
VOLUME


   MAXIMUM
TERM IN YEARS


     BUY

   SELL

      BUY

   SELL

  

Commodity

                             

Natural Gas (MDth)

   85    10,980    <1    95    10,950     

NGL (MBbl)

   —      1,644    <1    —      —      <1

 

In July 2003, we entered into an eight-year interest rate swap agreement to provide for a floating interest rate on $250 million of our 8  1 / 2 % senior subordinated notes due 2011. With this swap agreement, we will pay the counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was 1.55% at December 31, 2003) and receive a fixed rate of 8  1 / 2 %.

 

As of December 31, 2003, and 2002, our carrying amounts of cash and cash equivalents, short-term borrowings, and trade receivables and payables are representative of fair value because of the short-term nature of these instruments. The fair value of long-term debt with variable interest rates approximates its carrying value because the variable interest rates on these loans reprice frequently to reflect currently available interest rates. We estimated the fair value of debt with fixed interest rates based on quoted market prices for the same or similar issues. We estimated the fair value of all derivative financial instruments from prices indicated for the same or similar commodity transactions for a specific index.

 

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Credit Risk

 

Credit risk relates to the risk of loss that we would incur as a result of our customers’ failure to pay. Our customers are concentrated in the energy sector, and the creditworthiness of several industry participants have been called into question. We maintain credit policies to minimize overall credit risk. We monitor our exposure to and determine, as appropriate, whether we should request prepayments, letters of credit or other collateral from our counterparties.

 

8. PARTNERS’ CAPITAL

 

General

 

As of December 31, 2003, we had 58,404,649 common units outstanding. Common units totaling 48,020,404 are owned by the public, representing an 82.2 percent common unit interest in us. As of December 31, 2003, El Paso Corporation, through its subsidiaries, owned 10,384,245 common units, or 17.8 percent of our outstanding common units, all of our 10,937,500 Series C units and 50 percent of our one percent general partner interest.

 

Offering of Common Units

 

During 2003, we issued the following common units in public offerings:

 

OFFERING DATE


  

COMMON UNITS

ISSUED


  

PUBLIC OFFERING

PRICE


  

NET OFFERING

PROCEEDS


          (PER UNIT)    (IN THOUSANDS)

October 2003

   4,800,000    $ 40.60    $ 186.1

August 2003

   507,228    $ 39.43    $ 19.7

June 2003

   1,150,000    $ 36.50    $ 40.3

May 2003(1)

   1,118,881    $ 35.75    $ 38.3

April 2003

   3,450,000    $ 31.35    $ 103.1

(1) Offering includes 80 Series F convertible units offered. Refer to description below.

 

In addition to our public offerings of common units, in October 2003, we sold 3,000,000 common units privately to Goldman Sachs in connection with their purchase of a 9.9 percent membership interest in our general partner. We used the net proceeds of $111.5 million from that private sale and the net proceeds from the other common unit public offerings to temporarily reduce amounts outstanding under our revolving credit facility, senior subordinated notes, and for general partnership purposes.

 

In May 2003, we issued 1,118,881 common units and 80 Series F convertible units in a registered offering to a large institutional investor for approximately $38.3 million net of offering costs. Our Series F convertible units are not listed on any securities exchange or market. Each Series F convertible unit is comprised of two separate detachable units—a Series F1 convertible unit and a Series F2 convertible unit—that have identical terms except for vesting and termination dates and the number of underlying common units into which they may be converted. The Series F1 units are convertible into up to $80 million of common units anytime after August 12, 2003, and until the date we merge with Enterprise (subject to other defined extension rights). The Series F2 units are convertible into up to $40 million of common units. The Series F2 units terminate on March 30, 2005 (subject to defined extension rights). The price at which the Series F convertible units may be converted to common units is equal to the lesser of (i) the prevailing price (as defined below), if the prevailing price is equal to or greater than $35.75, or (ii) the prevailing price minus the product of 50 percent of the positive difference, if any, of $35.75 minus the prevailing price. The prevailing price is equal to the lesser of (i) the average closing

 

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price of our common units for the 60 business days ending on and including the fourth business day prior to our receiving notice from the holder of the Series F convertible units of their intent to convert them into common units; (ii) the average closing price of our common units for the first seven business days of the 60 day period included in (i); or (iii) the average closing price of our common units for the last seven days of the 60 day period included in (i). The price at which the Series F convertible units could have been converted to common units, assuming we had received a conversion notice on December 31, 2003 and March 2, 2004, was $40.38 and $39.40. The Series F convertible units may be converted into a maximum of 8,329,679 common units. Holders of Series F convertible units are not entitled to vote or receive distributions. The $4.1 million value associated with the Series F convertible units is included in partners’ capital as a component of common units capital.

 

In August 2003, we amended the terms of the Series F convertible units to permit the holder to elect a “cashless” exercise—that is, an exercise where the holder gives up common units with a value equal to the exercise price rather than paying the exercise price in cash. If the holder so elects, we have the option to settle the net position by issuing common units or, if the settlement price per unit is above $26.00 per unit, paying the holder an amount of cash equal to the market price of the net number of units. These amendments had no effect on the classification of the Series F convertible units on the balance sheet at December 31, 2003.

 

In the first quarter of 2004, 45 Series F1 convertible units were converted into 1,146,418 common units, for which the holder of the convertible units paid us $45 million.

 

Any Series F convertible units outstanding at the merger date will be converted into rights to receive Enterprise common units, subject to the restrictions governing the Series F units. The number of Enterprise common units and the price per unit at conversion will be adjusted based on the 1.81 exchange ratio.

 

In connection with the offerings in 2003, our general partner contributed to us approximately $2.0 million of our Series B preference units and cash of $3.1 million in order to maintain its one percent general partner interest.

 

In April 2002, we completed simultaneous offerings of 4,083,938 common units, which included a public offering of 3,000,000 common units and a private offering, at the same unit price, of 1,083,938 common units to our general partner (pursuant to our general partner’s anti-dilution rights under our partnership agreement) as a transaction not involving a public offering. We used the net cash proceeds of approximately $149 million to reduce indebtedness under EPN Holding’s term credit facility. Also in April 2002, we issued in a private offering 159,497 common units at the then-current market price of $37.74 per unit to a subsidiary of El Paso Corporation as partial consideration for our acquisition of the EPN Holding assets. In addition, our general partner contributed approximately $0.6 million in cash to us in April 2002 in order to maintain its one percent capital account balance.

 

In October 2001, we completed simultaneous offerings of 5,627,070 common units, which included a public offering of 4,150,000 common units and a private offering, at the same unit price, of 1,477,070 common units to our general partner (pursuant to our general partner’s anti-dilution rights under our partnership agreement) as a transaction not involving a public offering. We used the net cash proceeds of approximately $212 million to redeem 44,608 of our Series B preference units for their liquidation value of $50 million and to reduce the balance outstanding under our revolving credit facility. In addition, our general partner contributed $2.1 million in cash to us in order to satisfy its one percent contribution requirement.

 

In March 2001, we completed a public offering of 2,250,000 common units. We used the net cash proceeds of $66.6 million from the offering to reduce the balance outstanding under our revolving credit facility. In addition, our general partner contributed $0.7 million to us in order to satisfy its one percent capital contribution requirement.

 

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Series B Preference Units

 

In August 2000, we issued 170,000 Series B preference units with a value of $170 million to acquire the Petal and Hattiesburg natural gas storage businesses. In October 2001, we redeemed 44,608 of the Series B preference units for $50 million liquidation value including accrued distributions of approximately $5.4 million, bringing the total number of units outstanding to 125,392. As of December 31, 2002, the liquidation value of the outstanding Series B preference units was approximately $158 million. In October 2003, we redeemed all 123,865 of our remaining outstanding Series B preference units for $156 million, a 7 percent discount from their liquidation value of $167 million. For this redemption, we used borrowings under our revolving credit facility. We reflected the discount as an increase to the common units capital, Series C units capital and to our general partner’s capital accounts.

 

Series C Units

 

In November 2002, we issued to a subsidiary of El Paso Corporation 10,937,500 of Series C units at a price of $32 per unit, $350 million in the aggregate, as part of our consideration paid for the San Juan assets. The issuance of the Series C units was an exempt transaction under Section 4(2) of the Securities Act of 1993 as a transaction not involving a public offering. The Series C units are similar to our existing common units, except that the Series C units are non-voting. After April 30, 2003, the holder of the Series C units has the right to cause us to propose a vote of our common unitholders as to whether the Series C units should be converted into common units. If our common unitholders approve the conversion, then each Series C unit can convert into a common unit. If our common unitholders do not approve the conversion within 120 days after the vote is requested, then the distribution rate for the Series C units will increase to 105 percent of the common unit distribution rate in effect from time to time. Thereafter, the Series C unit distribution rate will increase on April 30, 2004, to 110 percent of the common unit distribution rate and on April 30, 2005, to 115 percent of the common unit distribution rate. In addition, our general partner contributed $3.5 million to us in order to satisfy its one percent capital contribution requirement. The holder of the Series C units has thus far not requested a vote to convert the Series C units into common units. As part of the proposed merger with Enterprise, Enterprise will purchase from a subsidiary of El Paso Corporation all of our outstanding Series C units. These units will not be converted to Enterprise common units in the merger but rather will remain limited partnership interests in GulfTerra after the closing of the merger transaction and, as such interest, will lose their GulfTerra common unit conversion and distribution rights.

 

Cash Distributions

 

We make quarterly distributions of 100 percent of our available cash, as defined in the partnership agreement, to our unitholders and to our general partner. Available cash generally consists of all cash receipts plus reductions in reserves less all cash disbursements and net additions to reserves. Our general partner has broad discretion to establish cash reserves for any proper partnership purpose. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders and our general partner, reserves to reduce debt, or, as necessary, reserves to comply with the terms of our agreements or obligations.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Cash distributions on common units, Series C units and to our general partner are discretionary in nature and are not entitled to arrearages of minimum quarterly distributions. The following table reflects our per unit cash distributions to our common unitholders and the total distributions paid to our common unitholders, Series C unitholder and general partner during the year ended December 31, 2003:

 

MONTH PAID


  

COMMON

UNIT


  

COMMON

UNITHOLDERS


  

SERIES C

UNITHOLDER


  

GENERAL

PARTNER


     (PER UNIT)    (IN MILLIONS)     

February

   $ 0.675    $ 29.7    $ 7.4    $ 15.0
    

  

  

  

May

   $ 0.675    $ 32.0    $ 7.4    $ 15.9
    

  

  

  

August

   $ 0.700    $ 34.8    $ 7.7    $ 18.0
    

  

  

  

November

   $ 0.710    $ 41.4    $ 7.8    $ 21.2
    

  

  

  

 

In January 2004, we declared a cash distribution of $0.71 per common and Series C unit, $49.3 million in aggregate, for the quarter ended December 31, 2003, which we paid on February 14, 2004. In addition, we paid our general partner $21.3 million related to its general partner interest. At the current distribution rates, our general partner receives approximately 30.2 percent of our total cash distributions for its role as our general partner.

 

Option Plans

 

In August 1998, we adopted the 1998 Omnibus Compensation Plan (Omnibus Plan) to provide our general partner with the ability to issue unit options to attract and retain the services of knowledgeable officers and key management personnel. Unit options to purchase a maximum of 3 million common units may be issued pursuant to the Omnibus Plan. Unit options granted to date pursuant to the Omnibus Plan are not immediately exercisable. For unit options granted in 2001, one-half of the unit options are considered vested and exercisable one year after the date of grant and the remaining one-half of the unit options are considered vested and exercisable one year after the first anniversary of the date of grant. These unit options expire ten years from such grant date, but shall be subject to earlier termination under certain circumstances. No grants of unit options were made in 2002. During 2003, under our Omnibus Plan, we granted 17,500 unit options, 25,000 time-vested restricted units and will grant 25,000 restricted units, if certain performance targets are achieved, to employees of El Paso Field Services whose primary responsibilities are the commercial management of our assets.

 

In August 1998, we also adopted the 1998 Common Unit Plan for Non-Employee Directors (Director Plan), formerly the 1998 Unit Option Plan for Non-Employee Directors, to provide our general partner with the ability to issue unit options to attract and retain the services of knowledgeable directors. Unit options and restricted units to purchase a maximum of 100,000 of our common units may be issued pursuant to the Director Plan. Under the Director Plan, each non-employee director receives a grant of 2,500 unit options upon initial election to the Board of Directors and an annual unit option grant of 2,000 unit options and, beginning in 2001, an annual restricted unit grant equal to the director’s annual retainer (including Chairman’s retainers, if applicable) divided by the fair market value of the common units on the grant date upon each re-election to the Board of Directors. Each unit option that is granted will vest immediately at the date of grant and will expire ten years from such date, but will be subject to earlier termination in the event that such non-employee director ceases to be a director of our general partner for any reason, in which case the unit options expire 36 months after such date except in the case of death, in which case the unit options expire 12 months after such date. Each director receiving a grant of restricted units is recorded as a unitholder and has all the rights of a unitholder with respect to such units, including the right to distributions on those units. The restricted units are nontransferable during the director’s service on the Board of Directors. The restrictions on the restricted units will end and the director will receive

 

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one common unit for each restricted unit granted upon the director’s termination. The Director Plan is administered by a management committee consisting of the Chairman of the Board of Directors of the general partner and such other senior officers of our general partner or its affiliates as the Chairman may designate. During 2003, under the Director Plan, we granted 5,226 restricted units at a fair value per unit of $36.37 and 10,500 unit options with a grant price of $35.92. Restricted units awards representing 5,429 and 4,090 were granted during 2002 and 2001 with a fair value of $32.23 and $33.00 per unit. As of December 31, 2003, 12,292 restricted units were outstanding.

 

We have accounted for all of these unit options and restricted units, except for the unit options issued to non-employee directors, in accordance with SFAS No. 123. Under SFAS No. 123, we report the fair value of these issuances as deferred compensation. Deferred compensation is amortized to compensation expense over the respective vesting or performance period. We have accounted for the unit options issued to the non-employee directors of our general partner’s Board of Directors in accordance with APB No. 25.

 

We issued time-vested restricted units and the performance-based restricted units at fair value at their date of grant. The restrictions on the time-vested units will lapse in four years from the date of grant. The restrictions on the performance-based restricted units will lapse if we achieve a specified level of target performance for identified “greenfield” projects by June 1, 2007 (for the 15,000 performance-based restricted units issued in June 2003) and by August 1, 2007 (for the 10,000 performance-based restricted units issued in August 2003). If we do not reach those targets by the applicable dates, the performance-based units will be forfeited. We will amortize the fair value of the time-vested restricted units over their four-year restricted period and the fair value of the performance-based restricted units over their performance periods. The performance-based restricted units are not entitled to vote or to receive distributions, until after (and if) we achieve specified level of target performance. The restricted units issued to non-employee directors of our general partner’s Board of Directors were issued at fair value at their date of grant. This fair value is being amortized to compensation expense over the period of service, which we have estimated to be one year.

 

Total unamortized deferred compensation as of December 31, 2003 and 2002 was approximately $1.5 million and $1.2 million. Our 2001 deferred compensation is fully amortized. Deferred compensation is reflected as a reduction of partners’ capital and is allocated 1 percent to our general partner and 99 percent to our limited partners.

 

The following table summarizes activity under the Omnibus Plan and Director Plan (excluding our restricted units) as of and for the years ended December 31, 2003, 2002 and 2001.

 

    2003

  2002

  2001

   

# UNITS OF

UNDERLYING

OPTIONS


 

WEIGHTED

AVERAGE

EXERCISE

PRICE


 

# UNITS OF

UNDERLYING

OPTIONS


 

WEIGHTED

AVERAGE

EXERCISE

PRICE


 

# UNITS OF

UNDERLYING

OPTIONS


 

WEIGHTED

AVERAGE

EXERCISE

PRICE


Outstanding at beginning of year

  1,550,000   $ 32.17   1,614,500   $ 32.09   925,500   $ 27.15

Granted

  28,000     35.08   8,000     32.23   1,016,500     35.00

Exercised

  318,000     31.74   42,500     27.19   307,500     27.17

Forfeited

  —       —     —       —     —       —  

Canceled

  144,000     34.99   30,000     34.99   20,000     27.19
   
       
       
     

Outstanding at end of year

  1,116,000   $ 32.00   1,550,000   $ 32.17   1,614,500   $ 32.09
   
       
       
     

Options exercisable at end of year

  1,106,000   $ 31.98   1,068,500   $ 30.88   606,500   $ 27.22
   
       
       
     

 

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The fair value of each unit option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions:

 

ASSUMPTION


   2003

    2002

    2001

 

Expected term in years

   7     8     8  

Expected volatility

   28.93 %   31.05 %   27.50 %

Expected distributions

   8.88 %   8.09 %   9.55 %

Risk-free interest rate

   3.31 %   3.24 %   5.05 %

 

The Black-Scholes weighted average fair value of options granted during 2003, 2002, and 2001 was $3.55, $3.71, and $2.62 per unit option, respectively.

 

Options outstanding as of December 31, 2003, are summarized below:

 

    OPTIONS OUTSTANDING

  OPTIONS EXERCISABLE

RANGE OF
EXERCISE PRICES


 

NUMBER

OUTSTANDING


 

WEIGHTED AVERAGE

REMAINING

CONTRACTUAL LIFE


 

WEIGHTED

AVERAGE

EXERCISE PRICE


 

NUMBER

EXERCISABLE


 

WEIGHTED

AVERAGE

EXERCISE PRICE


$19.86 to $27.80   423,500   4.6   $ 27.13   423,500   $ 27.13
$27.80 to $39.72   692,500   6.9   $ 34.99   682,500   $ 34.99
   
           
     
$19.86 to $39.72   1,116,000   6.0   $ 32.00   1,106,000   $ 31.98
   
           
     

 

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9. EARNINGS PER COMMON UNIT

 

The following table sets forth the computation of basic and diluted earnings per common unit (in thousands, except for unit amounts):

 

     FOR THE YEARS ENDED DECEMBER 31,

             2003        

           2002        

           2001        

Numerator:

                    

Numerator for basic earnings per common unit—

                    

Income from continuing operations

   $ 65,155    $ 34,275    $ 12,174

Income from discontinued operations

     —        5,085      1,086

Cumulative effect of accounting change

     1,340      —        —  
    

  

  

     $ 66,495    $ 39,360    $ 13,260
    

  

  

Denominator:

                    

Denominator for basic earnings per common unit— weighted-average common units

     49,953      42,814      34,376

Effect of dilutive securities:

                    

Unit options

     177      —        —  

Restricted units

     15      —        —  

Series F convertible units

     86      —        —  
    

  

  

Denominator for diluted earnings per common unit—
adjusted for weighted-average common units

     50,231      42,814      34,376
    

  

  

Basic earnings per common unit

                    

Income from continuing operations

   $ 1.30    $ 0.80    $ 0.35

Income from discontinued operations

     —        0.12      0.03

Cumulative effect of accounting change

     0.03      —        —  
    

  

  

     $ 1.33    $ 0.92    $ 0.38
    

  

  

Diluted earnings per common unit

                    

Income from continuing operations

   $ 1.30    $ 0.80    $ 0.35

Income from discontinued operations

     —        0.12      0.03

Cumulative effect of accounting change

     0.02      —        —  
    

  

  

     $ 1.32    $ 0.92    $ 0.38
    

  

  

 

10. RELATED PARTY TRANSACTIONS

 

The majority of our related party transactions are with affiliates of our general partner. Under an agreement that was in place before an indirect subsidiary of El Paso Corporation purchased our general partner, an affiliate of our general partner was obligated to provide individuals to perform the day to day financial, administrative, accounting and operational functions for us. As our activities increased, the fee for such services has also increased. Further, we provide services to various El Paso Corporation subsidiaries and, in turn, they provide us services. In addition, we have acquired a number of assets from subsidiaries of El Paso Corporation. We have not had any material transactions with Enterprise, other than the merger agreement transactions, since Enterprise acquired 50 percent of our general partner.

 

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The following table provides summary data of our transactions with related parties for the years ended December 31:

 

     2003

   2002

   2001

     (IN THOUSANDS)

Revenues received from related parties:

                    

Natural gas pipelines and plants

   $ 84,375    $ 159,608    $ 20,710

Oil and NGL Logistics

     29,413      26,288      25,249

Platform services(1)

     —        —        35

Natural gas storage

     —        3,016      2,325

Other(1)

     —        9,809      5,676
    

  

  

     $ 113,788    $ 198,721    $ 53,995
    

  

  

Expenses paid to related parties:

                    

Purchased natural gas costs

   $ 33,148    $ 22,784    $ 34,768

Operation and maintenance

     91,208      60,458      33,721
    

  

  

     $ 124,356    $ 83,242    $ 68,489
    

  

  

Reimbursements received from related parties:

                    

Operation and maintenance

   $ 2,426    $ 2,100    $ 11,499
    

  

  


(1) In addition to revenues from continuing operations reflected above, we also received revenues from related parties in 2002 and 2001 of $6.8 million and $8.2 million for our Prince TLP and $1.0 million and $0.7 million for our 9 percent overriding royalty interest which are included in income from discontinued operations on our income statements.

 

For the years ended December 31, 2003, 2002 and 2001, revenues received from related parties consisted of approximately 13%, 43% and 28% of our revenue from continuing operations. Also, we have undertaken efforts to reduce our transactions with El Paso Merchant Energy North America Company (Merchant Energy) and as of June 30, 2003, we replaced all our month-to-month arrangements that were previously with Merchant Energy with similar arrangements with third parties.

 

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The following table provides summary data categorized by our related parties for the years ended December 31:

 

     2003

   2002

   2001

     (IN THOUSANDS)

Revenues received from related parties:

                    

El Paso Corporation

                    

El Paso Merchant Energy North America Company

   $ 30,146    $ 92,675    $ 16,433

El Paso Production Company(1)

     9,109      9,054      4,230

Southern Natural Gas Company

     13      112      277

Tennessee Gas Pipeline Company

     93      —        638

El Paso Field Services

     74,427      96,880      32,382

Unconsolidated Subsidiaries

                    

Manta Ray Offshore(2)

     —        —        35
    

  

  

     $ 113,788    $ 198,721    $ 53,995
    

  

  

Purchased natural gas costs paid to related parties:

                    

El Paso Corporation

                    

El Paso Merchant Energy North America Company

   $ 27,777    $ 19,226    $ 28,169

El Paso Production Company

     —        2,251      6,412

Southern Natural Gas Company

     143      245      187

Tennessee Gas Pipeline Company

     —        70      —  

El Paso Field Services

     5,181      950      —  

El Paso Natural Gas Company

     47      42      —  
    

  

  

     $ 33,148    $ 22,784    $ 34,768
    

  

  

Operating expenses paid to related parties:

                    

El Paso Corporation

                    

El Paso Field Services

   $ 90,925    $ 60,000    $ 33,187

Unconsolidated Subsidiaries Poseidon Oil Pipeline Company

     283      458      534
    

  

  

     $ 91,208    $ 60,458    $ 33,721
    

  

  

Reimbursements received from related parties:

                    

Unconsolidated Subsidiaries

                    

Deepwater Holdings(3)

   $ —      $ —      $ 9,399

Poseidon Oil Pipeline Company

     2,426      2,100      2,100
    

  

  

     $ 2,426    $ 2,100    $ 11,499
    

  

  


(1) In addition to revenues from continuing operations from El Paso Production Company reflected above, during 2002 and 2001 we also received revenues of $7.8 million and $8.9 million from El Paso Production Company which are included in income from discontinued operations in our income statements.
(2) We sold our interest in Manta Ray Offshore in January 2001 in connection with El Paso Corporation’s merger with the Coastal Corporation.
(3) In January 2001, Deepwater Holdings sold its Stingray and West Cameron subsidiaries. In April 2001, Deepwater Holdings sold its UTOS subsidiary. In October 2001, we acquired the remaining 50 percent of Deepwater Holdings, and as a result of this transaction, on a going forward basis, Deepwater Holdings is consolidated in our financial statements and our agreement with Deepwater Holdings terminated.

 

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Revenues received from related parties

 

EPN Holding Assets. Our revenues from related parties increased in 2002 as a result of our EPN Holding transaction in which we acquired gathering, transportation and processing contracts with affiliates of our general partner. For the years ended December 31, 2003 and 2002, we received $26.5 million and $68.9 million from El Paso Merchant Energy North America Company, $19.9 million and $35.8 million from El Paso Field Services and $3.4 million and $4.0 million from El Paso Production Company.

 

GTM Texas. In connection with our acquisition of GTM Texas in February 2001, we entered into a 20-year fee-based transportation and fractionation agreement with El Paso Field Services. Pursuant to this agreement, we receive a fixed fee for each barrel of NGL transported and fractionated by our facilities. Approximately 25 percent of our per barrel fee is escalated annually for increases in inflation. For the years ended December 31, 2003, 2002 and 2001, we received revenue of approximately $21.5 million, $26.0 million and $25.2 million related to this agreement.

 

Chaco processing plant. In connection with our Chaco transaction in October 2001, we entered into a 20-year fee-based processing agreement with El Paso Field Services. Pursuant to this agreement, we receive a fixed fee for each dekatherm of natural gas that we process at the Chaco plant. For the years ended December 31, 2002 and 2001, we received revenue of $29.6 million and $6.5 million related to this agreement. In accordance with the original construction financing agreements, the Chaco plant is under an operating lease to El Paso Field Services. For the years ended December 31, 2002 and 2001, we received $1.8 million and $0.6 million related to this lease. As a result of the San Juan asset acquisition in November 2002, the processing agreement and the operating lease were terminated.

 

Storage facilities. With the April 2002 acquisition of the EPN Holding assets, we purchased contracts held by Wilson Storage with El Paso Merchant Energy North America Company. For the year ended December 31, 2002, we received approximately $2.9 million from El Paso Merchant Energy North America Company for natural gas storage fees. El Paso Merchant Energy North America Company and Tennessee Gas Pipeline Company use our Petal and Hattiesburg storage facilities from time to time. For the years ended December 31, 2002 and 2001 we received approximately $0.1 million and $1.6 million from El Paso Merchant Energy North America Company for natural gas storage fees. For the year ended December 31, 2001 we received approximately $0.7 million from Tennessee Gas Pipeline Company.

 

Prince TLP. In September 2001, we placed our Prince TLP in service. Prior to April 1, 2002, we received a monthly demand charge of approximately $1.9 million as well as processing fees from El Paso Production Company related to production on the Prince TLP. For the year ended December 31, 2002 and the four months ended December 31, 2001, we received $6.8 million and $8.2 million in platform revenue related to this agreement. In connection with our acquisition of the EPN Holding assets from El Paso Corporation, in April 2002 we sold our Prince TLP to subsidiaries of El Paso Corporation and these revenues are reflected in our income from discontinued operations.

 

Production fields. Through 2000 we had agreed to sell substantially all of our oil and natural gas production to El Paso Merchant Energy North America Company on a month to month basis. The agreement provided fees equal to two percent of the sales value of crude oil and condensate and $0.015 per dekatherm of natural gas for marketing production. Beginning in the fourth quarter of 2000, we began selling our oil and natural gas directly to third parties and our oil and natural gas sales related to El Paso Merchant Energy North America Company were approximately $9.8 million and $5.7 million for years ended December 31, 2002 and 2001.

 

In October 1999, we farmed out our working interest in the Prince Field to El Paso Production Company. Under the terms of the farmout agreement, our net overriding royalty interest in the Prince Field increased to a

 

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weighted average of approximately nine percent. El Paso Production Company began production on the Prince Field in September 2001. For the year ended December 31, 2002 and the four months ended December 31, 2001, we recorded approximately $1.0 million and $0.7 million in revenues related to our overriding royalty interest in the Prince Field. In connection with our acquisition of the EPN Holding assets from El Paso Corporation, in April 2002 we sold our 9 percent overriding royalty interest in the Prince Field to subsidiaries of El Paso Corporation and these revenues are reflected in our income from discontinued operations.

 

GulfTerra Alabama Intrastate. Several El Paso Corporation subsidiaries buy and transport natural gas on our GulfTerra Alabama Intrastate system. For the years ended December 31, 2003, 2002 and 2001, we received approximately $0.7 million, $6.8 million and $8.3 million from El Paso Merchant Energy North America Company. For the years ended December 31, 2003, 2002 and 2001, we received approximately $4.5 million, $4.5 million and $4.2 million from El Paso Production Company. For the years ended December 31, 2003, 2002 and 2001, we received approximately $0.1 million, $0.1 million and $0.2 million from Southern Natural Gas Company.

 

HIOS. In October 2001, HIOS became a wholly-owned asset through our acquisition of the remaining 50 percent equity interest in Deepwater Holdings. HIOS is a natural gas transmission system that has entered into interruptible transportation agreements at a non-discounted rate of $0.1244. For the years ended December 31, 2003 and 2002 and approximately three months ended December 31, 2001, we received $0.1 million, $1.4 million and $0.8 million from El Paso Merchant Energy. For the year ended December 31, 2003 and 2002, we received $1.2 million and $0.6 million from El Paso Production Company.

 

Texas NGL assets. In connection with our acquisition of the San Juan assets in November, 2002, we entered into a 10-year transportation agreement with El Paso Field Services. Pursuant to this agreement, beginning January 1, 2003, we receive a fee of $1.5 million per year for transportation on our NGL pipeline which extends from Corpus Christi to near Houston. In addition, we provide transportation, fractionation, storage and terminaling services to El Paso Field Services, as well as to various third parties, typically under agreements of one year term or less. We received approximately $7.5 million and $0.3 million in revenues from El Paso Field Services for the years ended December 31, 2003 and 2002.

 

Other. In addition to the revenues discussed above, we received $2.8 million and $2.6 million from El Paso Merchant North America and $25.6 million and $3.3 million from El Paso Field Services during 2003 and 2002 for additional gathering and processing services. The 2003 increase in revenues for El Paso Field Services was primarily as a result of higher natural gas prices and NGL volumes sold to El Paso Field Services from our Big Thicket assets.

 

Unconsolidated Subsidiaries. For the years ended December 31, 2001 we received approximately $0.03 million from Manta Ray Offshore Gathering as platform access and processing fees related to our South Timbalier 292 platform and our Ship Shoal 332 platform. We sold our interest in Manta Ray Offshore in January 2001 in connection with El Paso’s merger with the Coastal Corporation.

 

Expenses paid to related parties

 

Cost of natural gas. Our cost of natural gas paid to related parties increased in 2003 and 2002 as a result of our San Juan assets acquisitions and our EPN Holding transaction in which we acquired contracts with affiliates of our general partner. For the year ended December 31, 2003, our San Juan assets had cost of natural gas expenses of $1.3 million from El Paso Merchant Energy North America and $0.3 million from El Paso Field Services. For the year ended December 31, 2003 and 2002, our EPN Holding assets had cost of natural gas expenses of $0.9 million and $0.3 million from El Paso Merchant Energy North America Company and $3.5 million and $0.4 million from El Paso Field Services relating to the GulfTerra Texas gathering system. GulfTerra

 

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Alabama Intrastate’s purchases of natural gas include transactions with affiliates of our general partner. For the years ended December 31, 2003, 2002 and 2001, we had natural gas purchases of approximately $25.6 million, $18.9 million and $28.2 million from El Paso Merchant Energy North America Company, and $0.1 million, $0.2 million and $0.2 million from Southern Natural Gas Company and $2.3 million and $6.4 million from El Paso Production Company for the years ended December 31, 2002 and 2001. We also receive lease and throughput fees from El Paso Field Services for Hattiesburg and Anse La Butte. For the year ended December 31, 2002 we received $0.5 million from El Paso Field Services related to these fees.

 

Operating Expenses. Substantially all of the individuals who perform the day-to-day financial, administrative, accounting and operational functions for us, as well as those who are responsible for directing and controlling us, are currently employed by El Paso Corporation. Under a general and administrative services agreement between subsidiaries of El Paso Corporation and us, a fee of approximately $0.8 million per month was charged to our general partner, and accordingly, to us, which is intended to approximate the amount of resources allocated by El Paso Corporation and its affiliates in providing various operational, financial, accounting and administrative services on behalf of our general partner and us. In April 2002, in connection with our acquisition of EPN Holding assets, our general and administrative services agreement was extended to December 31, 2005, and the fee increased to approximately $1.6 million per month. In November 2002, as a result of the San Juan assets acquisition, the monthly fee under our general and administrative services agreement increased by $1.3 million, bringing our total monthly fee to $2.9 million. We believe this fee approximates the actual costs incurred. Under the terms of the partnership agreement, our general partner is entitled to reimbursement of all reasonable general and administrative expenses and other reasonable expenses incurred by our general partner and its affiliates for, or on our behalf, including, but not limited to, amounts payable by our general partner to El Paso Corporation under its management agreement. We are also charged for insurance and other costs paid directly by El Paso Field Services on our behalf.

 

As we became operator of additional facilities or systems, acquired new operations or constructed new facilities, we entered into additional management and operating agreements with El Paso Field Services. All fees paid under these contracts approximate actual costs incurred.

 

The following table shows the amount El Paso Field Services charged us for each of our agreements for the year ended December 31:

 

     2003

   2002

   2001

     (IN THOUSANDS)

Basic management fee

   $ 34,800    $ 18,092    $ 9,300

Operating fees(1)

     52,924      38,422      19,821

Insurance and other costs

     3,201      3,486      4,066
    

  

  

     $ 90,925    $ 60,000    $ 33,187
    

  

  


(1) Operating fees increased from 2002 to 2003 and from 2001 to 2002 due to the acquisition of the San Juan assets and EPN Holding assets.

 

Cost Reimbursements. In connection with becoming the operator of Poseidon, we entered into an operating agreement in January 2001. All fees received under contracts approximate actual costs incurred.

 

Acquisitions

 

We have purchased assets from related parties. See Note 2 for a discussion of these asset acquisitions.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Other Matters

 

In addition to the related party transactions discussed above, pursuant to the terms of many of the purchase and sale agreements we have entered into with various entities controlled directly or indirectly by El Paso Corporation, we have been indemnified for potential future liabilities, expenses and capital requirements above a negotiated threshold. Specifically, an indirect subsidiary of El Paso Corporation has agreed to indemnify us for specific litigation matters to the extent the ultimate resolutions of these matters result in judgments against us. For a further discussion of these matters see Note 11, Commitments and Contingencies, Legal Proceedings. Some of our agreements obligate certain indirect subsidiaries of El Paso Corporation to pay for capital costs related to maintaining assets which were acquired by us, if such costs exceed negotiated thresholds. We have made claims for approximately $5 million for costs incurred during the year ended December 31, 2003 as costs exceeded the established thresholds for the year ended December 31, 2003.

 

We have also entered into capital contribution arrangements with entities owned by El Paso Corporation, including its regulated pipelines, in the past, and will most likely do so in the future, as part of our normal commercial activities in the Gulf of Mexico. We have an agreement to receive $6.1 million, of which $3.0 million has been collected, from ANR Pipeline Company for our Phoenix project. As of December 31, 2003, we have received $10.5 million from ANR Pipeline and $7.0 million from El Paso Field Services for the Marco Polo natural gas pipeline. In October 2003, we collected $2 million from Tennessee Gas Pipeline for our Medusa project. These amounts are reflected as a reduction in project costs. Regulated pipelines often contribute capital toward the construction costs of gathering facilities owned by others which are, or will be, connected to their pipelines. El Paso Field Services’ contribution is in anticipation of additional natural gas volumes that will flow through to its onshore natural gas processing facilities.

 

In August 2003, Arizona Gas Storage L.L.C., along with its 50 percent partner APACS Holdings L.L.C., sold their interest in Copper Eagle Gas Storage L.L.C. to El Paso Natural Gas Company (EPNG), a subsidiary of El Paso Corporation. Copper Eagle Gas Storage is developing a natural gas storage project located outside of Phoenix, Arizona. Arizona Gas Storage is an indirect 60 percent owned subsidiary of us and 40 percent owned by IntraGas US, a Gaz de France North American subsidiary. APACS Holdings L.L.C. is a wholly owned subsidiary of Pinnacle West Energy, a subsidiary of Pinnacle West Capital Corporation. We have the right to receive $6.2 million of the sale proceeds, including a note receivable for $4.9 million to be paid quarterly over the next twelve months, from EPNG and we recorded a gain of $882 thousand related to the sale of Copper Eagle. In the event of EPNG default, the Copper Eagle Gas Storage project will revert back to the original owners without compensation to EPNG.

 

In September 2003, we entered into a nonbinding letter of intent with Southern Natural Gas Company, a subsidiary of El Paso Corporation, regarding the proposed development and sale of a natural gas storage cavern and the proposed sale of an undivided interest in a pipeline and other facilities related to that natural gas storage cavern. The new storage cavern would be located at our storage complex near Hattiesburg, Mississippi. If Southern Natural Gas determines that there is sufficient market interest, it would purchase the land and mineral rights related to the proposed storage cavern and would pay our costs to construct the storage cavern and related facilities. Upon completion of the storage cavern, Southern Natural Gas would acquire an undivided interest in our Petal pipeline connected to the storage cavern. We would also enter into an arrangement with Southern Natural Gas under which we would operate the storage cavern and pipeline on its behalf.

 

Before we consummate this transaction, and enter into definitive transaction documents, the transaction must be recommended by the audit and conflicts committee of our general partner’s board of directors, which committee consists solely of directors meeting the independent director requirements established by the NYSE and the Sarbanes-Oxley Act, and then approved by our general partner’s full board of directors.

 

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In October 2003, we exchanged with El Paso Corporation its obligation to repurchase the Chaco plant from us in 19 years for additional assets (refer to Note 2). Also in October 2003, we redeemed all of our outstanding Series B preference units (refer to Note 8).

 

The counterparty for one of our San Juan hedging activities is J. Aron and Company, an affiliate of Goldman Sachs. Goldman Sachs was also a co-manager of our 4,800,000 public common unit offering in October 2003, and is one of the lenders under our revolving credit facility and owned 9.9 percent of our general partner during part of the fourth quarter of 2003.

 

Our accounts receivable due from related parties consisted of the following as of:

 

    

DECEMBER 31,

2003


  

DECEMBER 31,

2002


     (IN THOUSANDS)

El Paso Corporation

             

El Paso Merchant Energy North America Company

   $ 4,113    $ 30,512

El Paso Production Company

     5,991      4,346

Tennessee Gas Pipeline Company

     1,350      930

El Paso Field Services(1)

     16,571      36,071

El Paso Natural Gas Company

     4,255      1,033

ANR Pipeline Company

     1,600      671

Other

     830      627
    

  

       34,710      74,190
    

  

Unconsolidated Subsidiaries

             

Deepwater Gateway

     3,939      9,636

Cameron Highway

     9,302      —  

Other

     14      —  
    

  

       13,255      9,636
    

  

Total

   $ 47,965    $ 83,826
    

  


(1) The December 2002 receivable balance includes approximately $15 million of natural gas imbalances relating to our EPN Holding acquisition.

 

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Our accounts payable due to related parties consisted of the following as of:

 

    

DECEMBER 31,

2003


  

DECEMBER 31,

2002


     (IN THOUSANDS)

El Paso Corporation

             

El Paso Merchant Energy North America Company

   $ 7,523    $ 8,871

El Paso Production Company

     4,069      14,518

Tennessee Gas Pipeline Company

     1,278      1,319

El Paso Field Services(1)

     13,869      55,648

El Paso Natural Gas Company

     942      1,475

El Paso Corporation

     6,249      4,181

Southern Natural Gas

     1,871      —  

Other

     667      132
    

  

       36,468      86,144
    

  

Unconsolidated Subsidiaries

             

Deepwater Gateway

     2,268      —  

Other

     134      —  
    

  

       2,402      —  
    

  

Total

   $ 38,870    $ 86,144
    

  


(1) The December 2002 payable balance includes approximately $19 million of working capital adjustments relating to our EPN Holding acquisition due to El Paso Field Services; and approximately $22 million of natural gas imbalances relating to our EPN Holding acquisition.

 

In connection with the sale of our Gulf of Mexico assets in January 2001, El Paso Corporation agreed to make quarterly payments to us of $2.25 million for three years beginning March 2001 and ending with a $2 million payment in the first quarter of 2004. The present value of the amounts due from El Paso Corporation were classified as follows:

 

    

DECEMBER 31,

2003


  

DECEMBER 31,

2002


     (IN THOUSANDS)

Accounts receivable, net

   $ 1,960    $ 8,403

Other noncurrent assets

     —        1,960
    

  

     $ 1,960    $ 10,363
    

  

 

11. COMMITMENTS AND CONTINGENCIES

 

Legal Proceedings

 

Grynberg. In 1997, we, 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. No monetary relief has been specified in this case. These matters have

 

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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). Discovery is proceeding. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

 

Will Price (formerly Quinque). We, along with numerous other energy companies, are named defendants in Will Price, et al v. Gas Pipelines and Their Predecessors, et al, filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands, and seek certification of a nationwide class of natural gas working interest owners and natural gas royalty owners to recover royalties that they contend these owners should have received had the volume and heating value of natural gas produced from their properties been differently measured, analyzed, calculated and reported, together with prejudgment and postjudgment interest, punitive damages, treble damages, attorney’s fees, costs and expenses, and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. Plaintiffs’ motion for class certification of a nationwide class of natural gas working interest owners and natural gas royalty owners was denied on April 10, 2003. Plaintiffs were granted leave to file a Fourth Amended Petition, which narrows the proposed class to royalty owners in wells in Kansas, Wyoming and Colorado and removes claims as to heating content. A second class action petition has been filed as to heating content claims. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

 

In connection with our April 2002 acquisition of the EPN Holding assets, subsidiaries of El Paso Corporation have agreed to indemnify us against all obligations related to existing legal matters at the acquisition date, including the legal matters involving Leapartners, L.P., City of Edinburg, Houston Pipe Line Company LP, and City of Corpus Christi discussed below.

 

During 2000, Leapartners, L.P. filed a suit against El Paso Field Services and others in the District Court of Loving County, Texas, alleging a breach of contract to gather and process natural gas in areas of western Texas related to an asset now owned by GulfTerra Holding. In May 2001, the court ruled in favor of Leapartners and entered a judgment against El Paso Field Services of approximately $10 million. El Paso Field Services filed an appeal with the Eighth Court of Appeals in El Paso, Texas. On August 15, 2003 the Court of Appeals reversed the lower’s courts calculation of past judgment interest but otherwise affirmed the judgment. A motion for a rehearing was denied. A petition for review by the Texas Supreme Court has been filed.

 

Also, GulfTerra Texas Pipeline L.P., (GulfTerra Texas, formerly known as EPGT Texas Pipeline L.P.) now owned by GulfTerra Holding, was involved in litigation with the City of Edinburg concerning the City’s claim that GulfTerra Texas was required to pay pipeline franchise fees under a contract the City had with Rio Grande Valley Gas Company, which was previously owned by GulfTerra Texas and is now owned by Southern Union Gas Company. An adverse judgment against Southern Union and GulfTerra Texas was rendered in Hidalgo County State District court in December 1998 and found a breach of contract, and held both GulfTerra Texas and Southern Union jointly and severally liable to the City for approximately $4.7 million. The judgment relied on the single business enterprise doctrine to impose contractual obligations on GulfTerra Texas and Southern Union entities that were not parties to the contract with the City. GulfTerra Texas appealed this case to the Texas Supreme Court seeking reversal of the judgment rendered against GulfTerra Texas. The City sought a remand to the trial court of its claim of tortious interference against GulfTerra Texas. Briefs were filed and oral arguments were held in November 2002. In October 2003, the Texas Supreme Court issued an opinion in favor of GulfTerra Texas and Southern Union on all issues. The City has requested rehearing.

 

In December 2000, a 30-inch natural gas pipeline jointly owned by GulfTerra Intrastate, L.P. (GulfTerra Intrastate) now owned by GulfTerra Holding, and Houston Pipe Line Company LP ruptured in Mont Belvieu, Texas, near Baytown, resulting in substantial property damage and minor physical injury. GulfTerra Intrastate is

 

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the operator of the pipeline. Two lawsuits were filed in the state district court in Chambers County, Texas by eight plaintiffs, including two homeowners’ insurers. The suits sought recovery for physical pain and suffering, mental anguish, physical impairment, medical expenses, and property damage. Houston Pipe Line Company was added as an additional defendant. In accordance with the terms of the operating agreement, GulfTerra Intrastate agreed to assume the defense of and to indemnify Houston Pipe Line Company. As of December 31, 2003, all claims have now been settled and these settlements had no impact on our financial statements.

 

The City of Corpus Christi, Texas (the “City”) alleged that GulfTerra Texas and various Coastal entities owed it monies for past obligations under City ordinances that propose to tax GulfTerra Texas on its gross receipts from local natural gas sales for the use of street rights-of-way. Some but not all of the GulfTerra Texas pipe at issue has been using the rights-of-way since the 1960’s. In addition, the City demanded that GulfTerra Texas agree to a going-forward consent agreement in order for the GulfTerra Texas pipe and Coastal pipe to have the right to remain in the City rights-of-way. In December 2003, GulfTerra Texas and the City entered into a license agreement releasing GulfTerra Texas from any past obligations and providing certain rights for the use of the City rights-of-way and City owned property. This agreement was retroactive to October 1, 2002.

 

In August 2002, we acquired the Big Thicket assets, which consist of the Vidor plant, the Silsbee compressor station and the Big Thicket gathering system located in east Texas, for approximately $11 million from BP America Production Company (BP). Pursuant to the purchase agreement, we have identified environmental conditions that we are working with BP and appropriate regulatory agencies to address. BP has agreed to indemnify us for exposure resulting from activities related to the ownership or operation of these facilities prior to our purchase (i) for a period of three years for non-environmental claims and (ii) until one year following the completion of any environmental remediation for environmental claims. Following expiration of these indemnity periods, we are obligated to indemnify BP for environmental or non-environmental claims. We, along with BP and various other defendants, have been named in the following two lawsuits for claims based on activities occurring prior to our purchase of these facilities.

 

Christopher Beverly and Gretchen Beverly, individually and on behalf of the estate of John Beverly v. GulfTerra GC, L.P., et. al. In June 2003, the plaintiffs sued us in state district court in Hardin County, Texas. The plaintiffs are the parents of John Christopher Beverly, a two year old child who died on April 15, 2002, allegedly as the result of his exposure to arsenic, benzene and other harmful chemicals in the water supply. Plaintiffs allege that several defendants responsible for that contamination, including us and BP. Our connection to the occurrences that are the basis for this suit appears to be our August 2002 purchase of certain assets from BP, including a facility in Hardin County, Texas known as the Silsbee compressor station. Under the terms of the indemnity provisions in the Purchase and Sale Agreement between GulfTerra and BP, GulfTerra requested that BP indemnify GulfTerra for any exposure. BP has agreed to indemnify us in this matter.

 

Melissa Duvail, et. al., v. GulfTerra GC, L.P., et. al. In June 2003, seventy-four residents of Hardin County, Texas, sued us and others in state district court in Hardin County, Texas. The plaintiffs allege that they have been exposed to hazardous chemicals, including arsenic and benzene, through their water supply, and that the defendants are responsible for that exposure. As with the Beverly case, our connection with the occurrences that are the basis of this suit appears to be our August 2002 purchase of certain assets from BP, including a facility known as the Silsbee compressor station, which is located in Hardin County, Texas. Under the terms of the indemnity provisions in the Purchase and Sale Agreement between us and BP, BP has agreed to indemnify us for this matter.

 

In addition to the above matters, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business.

 

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For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we will establish the necessary accruals. As of December 31, 2003, we had no reserves for our legal matters.

 

While the outcome of our outstanding legal matters cannot be predicted with certainty, based on information known to date, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, results of operations or cash flows. As new information becomes available or relevant developments occur, we will establish accruals as appropriate.

 

Environmental

 

Each of our operating segments is subject to extensive federal, state, and local laws and regulations governing environmental quality and pollution control. These laws and regulations are applicable to each segment and require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. As of December 31, 2003, we had a reserve of approximately $21 million, included in other noncurrent liabilities, for remediation costs expected to be incurred over time associated with mercury meters. We assumed this liability in connection with our April 2002 acquisition of the EPN Holding assets. As part of the November 2002 San Juan assets acquisition, El Paso Corporation has agreed to indemnify us for all the known and unknown environmental liabilities related to the assets we purchased up to the purchase price of $766 million. We will only be indemnified for unknown liabilities for up to three years from the purchase date of this acquisition. In addition, we have been indemnified by third parties for remediation costs associated with other assets we have purchased. We expect to make capital expenditures for environmental matters of approximately $3 million in the aggregate for the years 2004 through 2008, primarily to comply with clean air regulations.

 

Shoup Air Permit Violation. On December 16, 2003, El Paso Field Services, L.P. received a Notice of Enforcement (NoE) from the Texas Commission on Environmental Quality (TCEQ) concerning alleged Clean Air Act violations at its Shoup, Texas plant. The NoE included a draft Agreed Order assessing a penalty of $365,750 for the cited violations. The alleged violations pertained to emission limit exceedences, testing, reporting, and recordkeeping issues in 2001. While the NoE was addressed to El Paso Field Services, L.P., the substance of the NoE also concerns equipment owned at the Shoup plant by Gulfterra GC, L.P. El Paso Field Services, L.P. has responded to the NoE and is preparing to meet with the TCEQ to discuss the alleged violations and the proposed penalty.

 

While the outcome of our outstanding environmental matters cannot be predicted with certainty, based on the information known to date and our existing accruals, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, results of operations or cash flows. It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. 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 increasingly strict environmental laws and regulations and claims for damages to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties relating to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate.

 

Rates and Regulatory Matters

 

Marketing Affiliate Final Rule. In November 2003, the FERC issued a Final Rule extending its standards of conduct governing the relationship between interstate pipelines and marketing affiliates to all energy affiliates.

 

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Since our HIOS natural gas pipeline and Petal natural gas storage facility, including the 60-mile Petal natural gas pipeline, are interstate facilities as defined by the Natural Gas Act, the regulations dictate how HIOS and Petal conduct business and interact with all energy affiliates of El Paso Corporation and us.

 

The standards of conduct require us, absent a waiver, to functionally separate our HIOS and Petal interstate facilities from our other entities. We must dedicate employees to manage and operate our interstate facilities independently from our other Energy Affiliates. This employee group must function independently and is prohibited from communicating non-public transportation information or customer information to its Energy Affiliates. Separate office facilities and systems are necessary because of the requirement to restrict affiliate access to interstate transportation information. The Final Rule also limits the sharing of employees and offices with Energy Affiliates. The Final Rule was effective on February 9, 2004, subject to possible rehearing. On that date, each transmission provider filed with FERC and posted on the internet website a plan and scheduling for implementing this Final Rule. By June 1, 2004, written procedures implementing this Final Rule will be posted on the internet website. Requests for rehearing have been filed and are pending. At this time, we cannot predict the outcome of these requests, but at a minimum, adoption of the regulations in the form outlined in the Final Rule will place additional administrative and operational burdens on us.

 

Pipeline Safety Final Rule. In December 2003, the U.S. Department of Transportation issued a Final Rule requiring pipeline operators to develop integrity management programs for gas transmission pipelines located where a leak or rupture could do the most harm in “high consequence areas,” or HCA. The final rule requires operators to (1) perform ongoing assessments of pipeline integrity; (2) identify and characterize applicable threats to pipeline segments that could impact an HCA; (3) improve data collection, integration and analysis; (4) repair and remediate the pipeline as necessary; and (5) implement preventive and mitigative actions. The final rule incorporates the requirements of the Pipeline Safety Improvement Act of 2002, a new bill signed into law in December 2002. The Final Rule is effective as of January 14, 2004. At this time, we cannot predict the outcome of this final rule.

 

Other Regulatory Matters. HIOS is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. HIOS operates under a FERC approved tariff that governs its operations, terms and conditions of service, and rates. We timely filed a required rate case for HIOS on December 31, 2002. The rate filing and tariff changes are based on HIOS’ cost of service, which includes operating costs, a management fee and changes to depreciation rates and negative salvage amortization. We requested the rates be effective February 1, 2003, but the FERC suspended the rate increase until July 1, 2003, subject to refund. As of July 1, 2003, HIOS implemented the requested rates, subject to a refund, and has established a reserve for its estimate of its refund obligation. We will continue to review our expected refund obligation as the rate case moves through the hearing process and may increase or decrease the amounts reserved for refund obligation as our expectation changes. The FERC has conducted a hearing on this matter and an initial decision is expected to be issued in April 2004.

 

During the latter half of 2002, we experienced a significant unfavorable variance between the fuel usage on HIOS and the fuel collected from our customers for our use. We believe a series of events may have contributed to this variance, including two major storms that hit the Gulf Coast Region (and these assets) in late September and early October of 2002. As of December 31, 2003, we had recorded fuel differences of approximately $8.2 million, which is included in other non-current assets. We are currently in discussions with the FERC as well as our customers regarding the potential collection of some or all of the fuel differences. At this time we are not able to determine what amount, if any, may be collectible from our customers. Any amount we are unable to resolve or collect from our customers will negatively impact our earnings.

 

In December 1999, GulfTerra Texas filed a petition with the FERC for approval of its rates for interstate transportation service. In June 2002, the FERC issued an order that required revisions to GulfTerra Texas’

 

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proposed maximum rates. The changes ordered by the FERC involve reductions to rate of return, depreciation rates and revisions to the proposed rate design, including a requirement to separately state rates for gathering service. FERC also ordered refunds to customers for the difference, if any, between the originally proposed levels and the revised rates ordered by the FERC. We believe the amount of any rate refund would be minimal since most transportation services are discounted from the maximum rate. GulfTerra Texas has established a reserve for refunds. In July 2002, GulfTerra Texas requested rehearing on certain issues raised by the FERC’s order, including the depreciation rates and the requirement to separately state a gathering rate. On February 25, 2004, the FERC issued an order denying GulfTerra Texas’ request for rehearing and ordered GulfTerra Texas to file, within 45 days from the issuance of the order, a calculation of refunds and a refund plan. Additionally, the FERC ordered GulfTerra Texas to file a new rate case or justification of existing rates within three years from the date of the order.

 

In July 2002, Falcon Gas Storage, a competitor, also requested late intervention and rehearing of the order. Falcon asserts that GulfTerra Texas’ imbalance penalties and terms of service preclude third parties from offering imbalance management services. The FERC denied Falcon’s late intervention on February 25, 2004. Meanwhile in December 2002, GulfTerra Texas amended its Statement of Operating Conditions to provide shippers the option of resolving daily imbalances using a third-party imbalance service provider.

 

Falcon filed a formal complaint in March 2003 at the Railroad Commission of Texas claiming that GulfTerra Texas’ imbalance penalties and terms of service preclude third parties from offering hourly imbalance management services on the GulfTerra Texas system. GulfTerra Texas filed a response specifically denying Falcon’s assertions and requesting that the complaint be denied. The Railroad Commission has set their case for hearing beginning on April 13, 2004. The City Board of Public Service of San Antonio filed an intervention in opposition to Falcon’s complaint.

 

While the outcome of all of our rates and regulatory matters cannot be predicted with certainty, based on information known to date, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, results of operations or cash flows. As new information becomes available or relevant developments occur, we will establish accruals as appropriate.

 

Joint Ventures

 

We conduct a portion of our business through joint venture arrangements (including our Cameron Highway, Deepwater Gateway and Poseidon joint ventures) we form to construct, operate and finance the development of our onshore and offshore midstream energy businesses. We are obligated to make our proportionate share of additional capital contributions to our joint ventures only to the extent that they are unable to satisfy their obligations from other sources including proceeds from credit arrangements.

 

Operating Lease

 

We have long-term operating lease commitments associated with the Wilson natural gas storage facility we acquired in April 2002 in connection with the EPN Holding acquisition. The term of the natural gas storage facility and base gas leases runs through January 2008, and subject to certain conditions, has one or more optional renewal periods of five years each at fair market rent at the time of renewal. We also have long-term operating lease commitments associated with two NGL storage facilities in Texas we acquired in November 2002 in connection with our San Juan asset acquisition. The leases covering these facilities expire in 2006 and 2012.

 

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The future minimum lease payments under these operating lease commitments as of December 31, 2003 are as follows (in millions):

 

2004

   $ 7

2005

     7

2006

     7

2007

     6

2008

     3

Thereafter

     2
    

Total minimum lease payments

   $ 32
    

 

Rental expense under operating leases was approximately $7.2 million and $3.9 million for the years ended December 31, 2003 and 2002. We did not have any operating leases prior to our acquisition of the EPN Holding assets in April 2002.

 

Other Matters

 

As a result of current circumstances generally surrounding the energy sector, the creditworthiness of several industry participants has been called into question. As a result of these general circumstances, we have established an internal group to monitor our exposure to and determine, as appropriate, whether we should request prepayments, letters of credit or other collateral from our counterparties.

 

12. ACCOUNTING FOR HEDGING ACTIVITIES

 

A majority of our commodity purchases and sales, which relate to sales of oil and natural gas associated with our production operations, purchases and sales of natural gas associated with pipeline operations, sales of natural gas liquids and purchases or sales of gas associated with our processing plants and our gathering activities, are at spot market or forward market prices. We use futures, forward contracts, and swaps to limit our exposure to fluctuations in the commodity markets and allow for a fixed cash flow stream from these activities. On January 1, 2001, we adopted the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. We did not have any derivative contracts in place at December 31, 2000, and therefore, there was no transition adjustment recorded in our financial statements. During 2003, 2002 and 2001, we entered into cash flow hedges.

 

In August 2002, we entered into a derivative financial instrument to hedge our exposure during 2003 to changes in natural gas prices relating to gathering activities in the San Juan Basin in anticipation of our acquisition of the San Juan assets. The derivative is a financial swap on 30,000 MMBtu per day whereby we receive a fixed price of $3.525 per MMBtu and pay a floating price based on the San Juan index. From August 2002 through our acquisition date, November 27, 2002, we accounted for this derivative through current earnings since it did not qualify for hedge accounting under SFAS No. 133. Through the acquisition date in 2002, we recognized a $0.4 million gain in the margin of our natural gas pipelines and plants segment. Beginning with the acquisition date in November 2002, we are accounting for this derivative as a cash flow hedge under SFAS No. 133. In February and August 2003, we entered into additional derivative financial instruments to continue to hedge our exposure during 2004 to changes in natural gas prices relating to gathering activities in the San Juan Basin. The derivatives are financial swaps on 30,000 MMBtu per day whereby we receive an average fixed price of $4.23 per MMBtu and pay a floating price based on the San Juan index. As of December 31, 2003 and 2002, the fair value of these cash flow hedges was a liability of $5.8 million and $4.8 million, as the market price at those dates was higher than the hedge price. For the year ended December 31, 2003, we reclassified approximately $9.8 million of unrealized accumulated loss related to these derivatives from accumulated other

 

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comprehensive income as a decrease in revenue. No ineffectiveness exists in our hedging relationship because all purchase and sale prices are based on the same index and volumes as the hedge transaction. In connection with our San Juan asset purchase, we also acquired the outstanding risk management positions at the Chaco plant. The value of these NGL and natural gas positions was a $0.5 million liability at the acquisition date and this amount was included in the working capital adjustments to the purchase price. These positions expired in December 2002.

 

In connection with our GulfTerra Alabama Intrastate operations, we have fixed price contracts with specific customers for the sale of predetermined volumes of natural gas for delivery over established periods of time. We entered into cash flow hedges in 2002 and 2003 to offset the risk of increasing natural gas prices. As of December 31, 2003, the fair value of these cash flow hedges was an asset of approximately $77 thousand. For the twelve months ended December 31, 2003, we reclassified approximately $218 thousand of unrealized accumulated gain related to these derivatives from accumulated other comprehensive income to earnings. As of December 31, 2002, the fair value of these cash flow hedges was an asset of $86 thousand. During the year ended December 31, 2002, we reclassified a loss of $1.4 million from other comprehensive income to earnings. No ineffectiveness exists in our hedging relationship because all purchase and sale prices are based on the same index and volumes as the hedge transaction.

 

Beginning in April 2002, in connection with our EPN Holding acquisition, we had swaps in place for our interest in the Indian Basin processing plant to hedge the price received for the sale of natural gas liquids. All of these hedges expired by December 31, 2002, and we recorded a loss of $163 thousand during 2002 for these cash flow hedges. We did not have any ineffectiveness in our hedging relationship since all sale prices were based on the same index as the hedge transaction.

 

During 2003, we entered into additional derivative financial instruments to hedge a portion of our business’ exposure to changes in NGL prices during 2003 and 2004. We entered into financial swaps for 3,500 barrels per day for February through June 2003, 3,200 barrels per day for July 2003, 4,900 barrels per day for August 2003, and 6,000 barrels per day for August 2003 through September 2004. The average fixed price received was $0.49 per gallon for 2003 and will be $0.47 per gallon for 2004 while we pay a monthly average floating price based on the OPIS average price for each month. As of December 31, 2003, the fair value of these cash flow hedges was a liability of $3.3 million. For the twelve months ended December 31, 2003, we reclassified approximately $0.4 million of unrealized accumulated loss related to these derivatives from accumulated other comprehensive income to earnings.

 

In January 2002, Poseidon entered into a two-year interest rate swap agreement to fix the variable LIBOR based interest rate on $75 million of its $185 million variable rate revolving credit facility at 3.49% over the life of the swap. Prior to April 2003, under its credit facility, Poseidon paid an additional 1.50% over the LIBOR rate resulting in an effective interest rate of 4.99% on the hedged notional amount. Beginning in April 2003, the additional interest Poseidon pays over LIBOR was reduced resulting in an effective fixed interest rate of 4.74% on the hedged notional amount. This interest rate swap expired on January 9, 2004. We have recognized as a reduction in income our 36 percent share of Poseidon’s realized loss on the interest rate swap of $1.7 million for the twelve months ended December 31, 2003, or $0.6 million, through our earnings from unconsolidated affiliates. As of December 31, 2002, the fair value of its interest rate swap was a liability of $1.4 million, as the market interest rate was lower than the hedge rate, resulting in accumulated other comprehensive loss of $1.4 million. We included our 36 percent share of this liability of $0.5 million as a reduction of our investment in Poseidon and as loss in accumulated other comprehensive income. Additionally, we recognized in income our 36 percent share of Poseidon’s realized loss of $1.2 million for the twelve months ended December 31, 2002, or $0.4 million, through our earnings from unconsolidated affiliates.

 

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We estimate the entire $9.0 million of unrealized losses included in accumulated other comprehensive income at December 31, 2003, will be reclassified from accumulated other comprehensive income as a reduction to earnings over the next 12 months. When our derivative financial instruments are settled, the related amount in accumulated other comprehensive income is recorded in the income statement in operating revenues, cost of natural gas and other products, or interest and debt expense, depending on the item being hedged. The effect of reclassifying these amounts to the income statement line items is recording our earnings for the period at the “hedged price” under the derivative financial instruments.

 

In July 2003, to achieve a better mix of fixed rate debt and variable rate debt, we entered into an eight-year interest rate swap agreement to provide for a floating interest rate on $250 million out of $480 million of our 8  1 / 2 % senior subordinated notes due 2011. With this swap agreement, we pay the counterparty a LIBOR based interest rate plus a spread of 4.20% (which rate was 1.55% at December 31, 2003) and receive a fixed rate of 8  1 / 2 %. We are accounting for this derivative as a fair value hedge under SFAS No. 133. As of December 31, 2003, the fair value of the interest rate swap was a liability included in non-current liabilities of approximately $7.4 million and the fair value of the hedged debt decreased by the same amount.

 

The counterparties for our San Juan hedging activities are J. Aron and Company, an affiliate of Goldman Sachs, and UBS Warburg. We do not require collateral and do not anticipate non-performance by these counterparties. Through June 2003, the counterparty for our GulfTerra Alabama Intrastate operations was El Paso Merchant Energy. Beginning in August 2003, the counterparty is UBS Warburg, and we do not require collateral or anticipate non-performance by this counterparty. The counterparty for our NGL hedging activities for the Indian Basin and Chaco plants is J. Aron and Company, an affiliate of Goldman Sachs. We do not require collateral and do not anticipate non-performance by this counterparty. The counterparty for Poseidon’s hedging activity is Credit Lyonnais. Poseidon does not require collateral and does not anticipate non-performance by this counterparty. Wachovia Bank is our counterparty on our interest rate swap on the 8  1 / 2 % notes, and we do not require collateral or anticipate non-performance by this counterparty.

 

13. SUPPLEMENTAL DISCLOSURES TO THE STATEMENTS OF CASH FLOWS

 

Cash paid for interest, net of amounts capitalized were as follows:

 

     YEAR ENDED DECEMBER 31,

     2003

   2002

   2001

     (IN THOUSANDS)

Interest

   $ 135,131    $ 73,598    $ 41,020

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Noncash investing and financing activities excluded from the consolidated statements of cash flows were as follows:

 

     YEAR ENDED DECEMBER 31,

     2003

   2002

   2001

     (IN THOUSANDS)

Investment in Cameron Highway Oil Pipeline Company Joint Venture

   $ 50,836    $ —      $ —  

Exchange with El Paso Corporation

     23,275      —        —  

Adoption of SFAS No. 143

     5,726      —        —  

Note receivable due to sale of Copper Eagle

     3,656              

Increase in property, plant and equipment, offset by accounts payable and other noncurrent liabilities due to purchase price adjustments

     377              

Acquisition of San Juan assets

                    

Issuance of Series C units

     —        350,000      —  

Investment in processing agreement classified to property, plant and equipment

     —        114,412      —  

Acquisition of EPN Holding assets

                    

Issuance of common units

     —        6,000      —  

Acquisition of additional 50 percent interest in Deepwater Holdings

                    

Working capital acquired

     —        —        7,494

 

14. MAJOR CUSTOMERS

 

The percentage of our revenue from major customers was as follows:

 

     YEAR ENDED DECEMBER 31,

 
     2003

     2002

     2001

 

Chevron

   14 %    —        —    

BHP Petroleum

   14 %    —        —    

Burlington Resources

   13 %    —        —    

El Paso Merchant Energy North America Company

   —        21 %    —    

El Paso Field Services

   —        18 %    16 %

Alabama Gas Corporation

   —        —        14 %

 

The 2003 major customers are a result of our San Juan asset acquisition in November 2002. Also, during 2003 we decreased our activities with affiliates of El Paso Corporation, including replacing all our month-to-month arrangements that were previously with El Paso Merchant Energy with similar arrangements with third parties. The 2002 percentage increase in revenue from El Paso Merchant Energy North America Company and El Paso Field Services is primarily due to our EPN Holding acquisition completed in 2002.

 

15. BUSINESS SEGMENT INFORMATION:

 

Each of our segments are business units that offer different services and products that are managed separately since each segment requires different technology and marketing strategies and we have segregated our business activities into four distinct operating segments:

 

    Natural gas pipelines and plants;

 

    Oil and NGL logistics;

 

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    Natural gas storage; and

 

    Platform services.

 

The accounting policies of the individual segments are the same as those described in Note 1. We record intersegment revenues at rates that approximate market.

 

We use performance cash flows (which we formerly referred to as EBITDA) to evaluate the performance of our segments, determine how resources will be allocated and develop strategic plans. We define performance cash flows as earnings before interest, income taxes, depreciation and amortization and other adjustments. Historically our lenders and equity investors have viewed our performance cash flows measure as an indication of our ability to generate sufficient cash to meet debt obligations or to pay distributions, we believe that there has been a shift in investors’ evaluation regarding investments in MLPs and they now put as much focus on the performance of an MLP investment as they do its ability to pay distributions. For that reason, we disclose performance cash flows as a measure of our segment’s performance. We believe performance cash flows is also useful to our investors because it allows them to evaluate the effectiveness of our business segments from an operational perspective, exclusive of the costs to finance those activities, income taxes and depreciation and amortization, none of which are directly relevant to the efficiency of those operations. This measurement may not be comparable to measurements used by other companies and should not be used as a substitute for net income or other performance measures.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Our operating results and financial position reflect the acquisitions of the San Juan assets in November 2002, the EPN Holding assets in April 2002, the Chaco plant and the remaining 50 percent interest we did not already own in Deepwater Holdings in October 2001 and GTM Texas in February 2001. The acquisitions were accounted for as purchases and therefore operating results of these acquired entities are included prospectively from the purchase date. The following are results as of and for the periods ended December 31:

 

   

NATURAL GAS

PIPELINES &

PLANTS


   

OIL AND

NGL LOGISTICS


 

NATURAL

GAS

STORAGE


 

PLATFORM

SERVICES


 

NON-SEGMENT

ACTIVITY(1)


    TOTAL

    (IN THOUSANDS)

FOR THE YEAR ENDED DECEMBER 31, 2003

                                       

Revenue from external customers

  $ 734,670     $ 53,850   $ 44,297   $ 20,861   $ 17,811     $ 871,489

Intersegment revenue

    127       —       278     2,603     (3,008 )     —  

Depreciation, depletion and amortization

    68,747       8,603     11,720     5,334     4,442       98,846

Earnings from unconsolidated investments

    2,377       8,098     898     —       —         11,373

Performance cash flows

    311,164       59,053     29,554     20,181     N/A       N/A

Assets

    2,289,546       464,246     315,853     162,275     89,660       3,321,580

FOR THE YEAR ENDED DECEMBER 31, 2002

                                       

Revenue from external customers(2)

  $ 357,581     $ 37,645   $ 28,602   $ 16,672   $ 16,890     $ 457,390

Intersegment revenue

    227       —       —       9,283     (9,510 )     —  

Depreciation, depletion and amortization

    44,479       6,481     8,503     4,205     8,458       72,126

Earnings from unconsolidated investments

    194       13,445     —       —       —         13,639

Performance cash flows

    167,185       43,347     16,629     29,224     N/A       N/A

Assets

    2,279,955       265,900     320,662     140,758     123,621       3,130,896

FOR THE YEAR ENDED DECEMBER 31, 2001

                                       

Revenue from external customers

  $ 100,683     $ 32,327   $ 19,373   $ 15,385   $ 25,638     $ 193,406

Intersegment revenue

    381       —       —       12,620     (13,001 )     —  

Depreciation, depletion and amortization

    12,378       5,113     5,605     4,154     7,528       34,778

Asset impairment charge

    3,921       —       —       —       —         3,921

Earnings (loss) from unconsolidated investments

    (9,761 )     18,210     —       —       —         8,449

Performance cash flows

    52,200       47,560     13,209     30,783     N/A       N/A

Assets

    563,698       195,839     226,991     115,364     69,968       1,171,860

(1)

Represents predominately our oil and natural gas production activities as well as intersegment eliminations. Our intersegment revenues, along with our intersegment operating expenses, consist of normal course of

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

 

business-type transactions between our operating segments. We record an intersegment revenue elimination, which is the only elimination included in the “Non-Segment Activity” column, to remove intersegment transactions.

(2) The revenue amount for our Oil and NGL Logistics segment has been reduced by $10.5 million to reflect the reclassification of Typhoon Oil Pipeline’s cost of sales and other products. See Note 1, Summary of Significant Accounting Policies, for a further discussion.

 

A reconciliation of our segment performance cash flows to our net income is as follows:

 

     YEARS ENDED DECEMBER 31,

     2003

   2002

    2001

Natural gas pipelines & plants

   $ 311,164    $ 167,185     $ 52,200

Oil & NGL logistics

     59,053      43,347       47,560

Natural gas storage

     29,554      16,629       13,209

Platform services

     20,181      29,224       30,783
    

  


 

Segment performance cash flows

     419,952      256,385       143,752

Plus: Other, nonsegment results

     15,107      10,427       17,688

Earnings from unconsolidated affiliates

     11,373      13,639       8,449

Income from discontinued operations

     —        5,136       1,097

Cumulative effect of accounting change

     1,690      —         —  

Noncash hedge gain

     —        411       —  

Noncash earnings related to future payments from El Paso Corporation

     —        —         25,404

Less: Interest and debt expense

     127,830      81,060       41,542

Loss due to early redemptions of debt

     36,846      2,434       —  

Depreciation, depletion and amortization

     98,846      72,126       34,778

Asset impairment charge

     —        —         3,921

Cash distributions from unconsolidated affiliates

     12,140      17,804       35,062

Minority interest

     917      (60 )     100

Net cash payment received from El Paso Corporation

     8,404      7,745       7,426

Discontinued operations of Prince facilities

     —        7,201       6,561

Loss on sale of Gulf of Mexico assets

     —        —         11,851
    

  


 

Net income

   $ 163,139    $ 97,688     $ 55,149
    

  


 

 

16. GUARANTOR FINANCIAL INFORMATION

 

In May 2001, we purchased our general partner’s 1.01 percent non-managing interest owned in twelve of our subsidiaries for $8 million. As a result of this acquisition, all our subsidiaries, but not our equity investees, are wholly owned by us. As of December 31, 2003, our credit facility is guaranteed by each of our subsidiaries, excluding our unrestricted subsidiaries (Arizona Gas Storage, L.L.C. and GulfTerra Arizona Gas, L.L.C.), and is collateralized by substantially all of our assets. In addition, all of our senior notes and senior subordinated notes are jointly, severally, fully and unconditionally guaranteed by us and all our subsidiaries, excluding our unrestricted subsidiaries. As of December 31, 2002, our revolving credit facility, GulfTerra Holding term credit facility, senior secured term loan and senior secured acquisition term loan are guaranteed by each of our subsidiaries, excluding our unrestricted subsidiaries (Matagorda Island Area Gathering System, Arizona Gas Storage, L.L.C. and GulfTerra Arizona Gas, L.L.C.), and are collateralized by our general and administrative services agreement, substantially all of our assets, and our general partner’s one percent general partner interest. In addition, as of December 31, 2002, all of our senior subordinated notes are jointly, severally, fully and

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

unconditionally guaranteed by us and all our subsidiaries excluding our unrestricted subsidiaries. The consolidating eliminations column on our condensed consolidating balance sheets below eliminates our investment in consolidated subsidiaries, intercompany payables and receivables and other transactions between subsidiaries. The consolidating eliminations column in our condensed consolidating statements of income and cash flows eliminates earnings from our consolidated affiliates.

 

Non-guarantor subsidiaries for the year ended December 31, 2003, consisted of our unrestricted subsidiaries (Arizona Gas Storage, L.L.C. and GulfTerra Arizona Gas, L.L.C.). Non-guarantor subsidiaries for the year ended December 31, 2002, consisted of Argo and Argo I for the quarter ended March 31, 2002, our GulfTerra Holding (then known as EPN Holding) subsidiaries, which owned the EPN Holding assets and equity interests in GulfTerra Holding (then known as EPN Holding), for the quarters ended June 30, 2002 and September 30, 2002, and our unrestricted subsidiaries for the quarter ended December 31, 2002. Non-guarantor subsidiaries for all other periods consisted of Argo and Argo I which owned the Prince TLP. As a result of our disposal of the Prince TLP and our related overriding royalty interest in April 2002, the results of operations and net book value of these assets are reflected as discontinued operations in our statements of income and assets held for sale in our balance sheets and Argo and Argo I became guarantor subsidiaries.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

CONDENSED CONSOLIDATING STATEMENT OF INCOME

FOR THE YEAR ENDED DECEMBER 31, 2003

 

    ISSUER

   

NON-GUARANTOR

SUBSIDIARIES


   

GUARANTOR

SUBSIDIARIES


 

CONSOLIDATING

ELIMINATIONS


   

CONSOLIDATED

TOTAL


 
    (IN THOUSANDS)  

Operating revenues

                                     

Natural gas pipelines and plants

                                     

Natural gas sales

  $ —       $ —       $ 171,738   $ —       $ 171,738  

NGL sales

    —         —         121,167     —         121,167  

Gathering and transportation

    —         815       387,962     —         388,777  

Processing

    —         —         52,988     —         52,988  
   


 


 

 


 


      —         815       733,855     —         734,670  
   


 


 

 


 


Oil and NGL logistics

                                     

Oil sales

    —         —         2,231     —         2,231  

Oil transportation

    —         —         26,769     —         26,769  

Fractionation

    —         —         22,034     —         22,034  

NGL Storage

    —         —         2,816     —         2,816  
   


 


 

 


 


      —         —         53,850     —         53,850  
   


 


 

 


 


Platform services

    —         —         20,861     —         20,861  

Natural gas storage

    —         —         44,297     —         44,297  

Other—oil and natural gas production

    —         —         17,811     —         17,811  
   


 


 

 


 


      —         815       870,674     —         871,489  
   


 


 

 


 


Operating expenses

                                     

Cost of natural gas and other products

    —         —         287,157     —         287,157  

Operation and maintenance

    5,908       279       183,515     —         189,702  

Depreciation, depletion and amortization

    148       42       98,656     —         98,846  

(Gain) loss on sale of long-lived assets

    (19,000 )     —         321     —         (18,679 )
   


 


 

 


 


      (12,944 )     321       569,649     —         557,026  
   


 


 

 


 


Operating income

    12,944       494       301,025     —         314,463  
   


 


 

 


 


Earnings from consolidated affiliates

    236,753       —         —       (236,753 )     —    

Earnings from unconsolidated affiliates

    —         898       10,475     —         11,373  

Minority interest expense

    —         (917 )     —       —         (917 )

Other income

    784       —         422     —         1,206  

Interest and debt expense (income)

    51,721       (3 )     76,112     —         127,830  

Loss due to early redemptions of debt

    35,621       —         1,225     —         36,846  
   


 


 

 


 


Income from continuing operations

    163,139       478       234,585     (236,753 )     161,449  

Cumulative effect of accounting change

    —         —         1,690     —         1,690  
   


 


 

 


 


Net income

  $ 163,139     $ 478     $ 236,275   $ (236,753 )   $ 163,139  
   


 


 

 


 


 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2002

 

    ISSUER

   

NON-GUARANTOR

SUBSIDIARIES(1)


 

GUARANTOR

SUBSIDIARIES


 

CONSOLIDATING

ELIMINATIONS


   

CONSOLIDATED

TOTAL


    (IN THOUSANDS)

Operating revenues

                                 

Natural gas pipelines and plants

                                 

Natural gas sales

  $ —       $ 30,778   $ 54,223   $ —       $ 85,001

NGL sales

    —         15,050     17,928     —         32,978

Gathering and transportation

    —         71,560     122,776     —         194,336

Processing

    —         5,316     39,950     —         45,266
   


 

 

 


 

      —         122,704     234,877     —         357,581
   


 

 

 


 

Oil and NGL logistics

                                 

Oil sales

    —         —       108     —         108

Oil transportation

    —         —       8,364     —         8,364

Fractionation

    —         —       26,356     —         26,356

NGL storage

    —         —       2,817     —         2,817
   


 

 

 


 

      —         —       37,645     —         37,645
   


 

 

 


 

Platform services

    —         —       16,672     —         16,672

Natural gas storage

    —         2,699     25,903     —         28,602

Other—oil and natural gas production

    —         —       16,890     —         16,890
   


 

 

 


 

      —         125,403     331,987     —         457,390
   


 

 

 


 

Operating expenses

                                 

Cost of natural gas and other products

    —         39,280     69,539     —         108,819

Operation and maintenance

    6,056       27,701     81,405     —         115,162

Depreciation, depletion and amortization

    274       10,729     61,123     —         72,126

Loss on sale of long-lived assets

    —         —       473     —         473
   


 

 

 


 

      6,330       77,710     212,540     —         296,580
   


 

 

 


 

Operating income

    (6,330 )     47,693     119,447     —         160,810
   


 

 

 


 

Earnings from consolidated affiliates

    64,851       —       29,714     (94,565 )     —  

Earnings from unconsolidated affiliates

    —         —       13,639     —         13,639

Minority interest income

    —         60     —       —         60

Other income

    1,471       5     61     —         1,537

Interest and debt expense (income)

    (37,696 )     22,048     96,708     —         81,060

Loss due to early redemptions of debt

    —         —       2,434     —         2,434
   


 

 

 


 

Income from continuing operations

    97,688       25,710     63,719     (94,565 )     92,552

Income from discontinued operations

    —         4,004     1,132     —         5,136
   


 

 

 


 

Net income

  $ 97,688     $ 29,714   $ 64,851   $ (94,565 )   $ 97,688
   


 

 

 


 


(1) Non-guarantor subsidiaries consisted of Argo and Argo I for the quarter ended March 31, 2002; EPN Holding subsidiaries for the quarters ended June 30, 2002 and September 30, 2002; and our unrestricted subsidiaries for the quarter ended December 31, 2002.

 

F-192


Table of Contents
Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

CONDENSED CONSOLIDATING STATEMENT OF INCOME

YEAR ENDED DECEMBER 31, 2001

 

    ISSUER

   

NON-GUARANTOR

SUBSIDIARIES(1)


 

GUARANTOR

SUBSIDIARIES


   

CONSOLIDATING

ELIMINATIONS


   

CONSOLIDATED

TOTAL


 
    (IN THOUSANDS)  

Operating revenues

                                     

Natural gas pipelines and plants

                                     

Natural gas sales

  $ —       $ —     $ 59,701     $ —       $ 59,701  

Gathering and transportation

    —         —       33,849       —         33,849  

Processing

    —         —       7,133       —         7,133  
   


 

 


 


 


      —         —       100,683       —         100,683  
   


 

 


 


 


Oil and NGL logistics

                                     

Oil transportation

    —         —       7,082       —         7,082  

Fractionation

    —         —       25,245       —         25,245  
   


 

 


 


 


      —         —       32,327       —         32,327  
   


 

 


 


 


Platform services

    —         —       15,385       —         15,385  

Natural gas storage

    —         —       19,373       —         19,373  

Other—oil and natural gas production

    —         —       25,638       —         25,638  
   


 

 


 


 


      —         —       193,406       —         193,406  
   


 

 


 


 


Operating expenses

                                     

Cost of natural gas and other products

    —         —       51,542       —         51,542  

Operation and maintenance

    (200 )     —       33,479       —         33,279  

Depreciation, depletion and amortization

    323       —       34,455       —         34,778  

Asset impairment charge

    —         —       3,921       —         3,921  

Loss on sale of long-lived assets

    10,941       —       426       —         11,367  
   


 

 


 


 


      11,064       —       123,823       —         134,887  
   


 

 


 


 


Operating income (loss)

    (11,064 )     —       69,583       —         58,519  
   


 

 


 


 


Earnings from consolidated affiliates

    22,393       —       1,308       (23,701 )     —    

Earnings from unconsolidated affiliates

    —         —       8,449       —         8,449  

Minority interest expense

    —         —       (100 )     —         (100 )

Other income

    28,492       —       234       —         28,726  

Interest and debt expense (income)

    (15,328 )     —       56,870       —         41,542  
   


 

 


 


 


Income from continuing operations

    55,149       —       22,604       (23,701 )     54,052  

Income (loss) from discontinued operations

    —         1,308     (211 )     —         1,097  
   


 

 


 


 


Net income

  $ 55,149     $ 1,308   $ 22,393     $ (23,701 )   $ 55,149  
   


 

 


 


 



(1) Non-guarantor subsidiaries consist of Argo and Argo I, which were formed in August 2000.

 

F-193


Table of Contents
Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

CONDENSED CONSOLIDATING BALANCE SHEETS

DECEMBER 31, 2003

 

    ISSUER

 

NON-GUARANTOR

SUBSIDIARIES


 

GUARANTOR

SUBSIDIARIES


 

CONSOLIDATING

ELIMINATIONS


   

CONSOLIDATED

TOTAL


    (IN THOUSANDS)

Current assets

                               

Cash and cash equivalents

  $ 30,425   $ —     $ —     $ —       $ 30,425

Accounts receivable, net

                               

Trade

    —       61     43,142     —         43,203

Unbilled trade

    —       52     63,015     —         63,067

Affiliates

    746,126     3,541     41,606     (743,308 )     47,965

Affiliated note receivable

    —       3,713     55     —         3,768

Other current assets

    3,573     —       17,022     —         20,595
   

 

 

 


 

Total current assets

    780,124     7,367     164,840     (743,308 )     209,023

Property, plant and equipment, net

    8,039     431     2,886,022     —         2,894,492

Intangible assets

    —       —       3,401     —         3,401

Investments in unconsolidated affiliates

    —       —       175,747     —         175,747

Investments in consolidated affiliates

    2,108,104     —       622     (2,108,726 )     —  

Other noncurrent assets

    199,761     —       9,155     (169,999 )     38,917
   

 

 

 


 

Total assets

  $ 3,096,028   $ 7,798   $ 3,239,787   $ (3,022,033 )   $ 3,321,580
   

 

 

 


 

Current liabilities

                               

Accounts payable

                               

Trade

  $ —     $ 22   $ 113,798   $ —       $ 113,820

Affiliates

    10,691     3,499     767,988     (743,308 )     38,870

Accrued gas purchase costs

    —       —       15,443     —         15,443

Accrued interest

    10,930     —       269     —         11,199

Current maturities of senior secured term loan

    3,000     —       —       —         3,000

Other current liabilities

    2,601     1     24,433     —         27,035
   

 

 

 


 

Total current liabilities

    27,222     3,522     921,931     (743,308 )     209,367

Revolving credit facility

    382,000     —       —       —         382,000

Senior secured term loans, less current maturities

    297,000     —       —       —         297,000

Long-term debt

    1,129,807     —       —       —         1,129,807

Other noncurrent liabilities

    7,413     —       211,629     (169,999 )     49,043

Minority interest

    —       1,777     —       —         1,777

Partners’ capital

    1,252,586     2,499     2,106,227     (2,108,726 )     1,252,586
   

 

 

 


 

Total liabilities and partners’ capital

  $ 3,096,028   $ 7,798   $ 3,239,787   $ (3,022,033 )   $ 3,321,580
   

 

 

 


 

 

F-194


Table of Contents
Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

CONDENSED CONSOLIDATING BALANCE SHEETS

DECEMBER 31, 2002

 

    ISSUER

   

NON-GUARANTOR

SUBSIDIARIES(1)


 

GUARANTOR

SUBSIDIARIES


 

CONSOLIDATING

ELIMINATIONS


   

CONSOLIDATED

TOTAL


    (IN THOUSANDS)

Current assets

                                 

Cash and cash equivalents

  $ 20,777     $ —     $ 15,322   $ —       $ 36,099

Accounts receivable, net

                                 

Trade

    —         36     90,343     —         90,379

Unbilled trade

    —         38     49,102     —         49,140

Affiliates

    709,230       3,055     67,513     (695,972 )     83,826

Other current assets

    1,118       —       2,333     —         3,451
   


 

 

 


 

Total current assets

    731,125       3,129     224,613     (695,972 )     262,895

Property, plant and equipment, net

    6,716       454     2,717,768     —         2,724,938

Intangible assets

    —         —       3,970     —         3,970

Investments in unconsolidated affiliates

    —         5,197     90,754     —         95,951

Investments in consolidated affiliates

    1,787,767       —       693     (1,788,460 )     —  

Other noncurrent assets

    205,262       —       7,879     (169,999 )     43,142
   


 

 

 


 

Total assets

  $ 2,730,870     $ 8,780   $ 3,045,677   $ (2,654,431 )   $ 3,130,896
   


 

 

 


 

Current liabilities

                                 

Accounts payable

                                 

Trade

  $ —       $ 302   $ 119,838   $ —       $ 120,140

Affiliates

    18,867       2,982     760,267     (695,972 )     86,144

Accrued interest

    14,221       —       807     —         15,028

Accrued gas purchase costs

    —         —       6,584     —         6,584

Current maturities of senior secured term loan

    5,000       —       —       —         5,000

Other current liabilities

    1,645       5     19,545     —         21,195
   


 

 

 


 

Total current liabilities

    39,733       3,289     907,041     (695,972 )     254,091

Revolving credit facility

    491,000       —       —       —         491,000

Senior secured term loans, less current maturities

    392,500       —       160,000     —         552,500

Long-term debt

    857,786       —       —       —         857,786

Other noncurrent liabilities

    (1 )     —       193,725     (169,999 )     23,725

Minority interest

    —         1,942     —       —         1,942

Partners’ capital

    949,852       3,549     1,784,911     (1,788,460 )     949,852
   


 

 

 


 

Total liabilities and partners’ capital

  $ 2,730,870     $ 8,780   $ 3,045,677   $ (2,654,431 )   $ 3,130,896
   


 

 

 


 


(1) Non-guarantor subsidiaries consisted of Argo and Argo I for the quarter ended March 31, 2002; EPN Holding subsidiaries for the quarters ended June 30, 2002 and September 30, 2002; and our unrestricted subsidiaries for the quarter ended December 31, 2002.

 

F-195


Table of Contents
Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW

YEAR ENDED DECEMBER 31, 2003

 

    ISSUER

   

NON-GUARANTOR

SUBSIDIARIES


   

GUARANTOR

SUBSIDIARIES


   

CONSOLIDATING

ELIMINATIONS


   

CONSOLIDATED

TOTAL


 
    (IN THOUSANDS)  

Cash flows from operating activities

                                       

Net income

  $ 163,139     $ 478     $ 236,275     $ (236,753 )   $ 163,139  

Less cumulative effect of accounting change

    —         —         1,690       —         1,690  
   


 


 


 


 


Income from continuing operations

    163,139       478       234,585       (236,753 )     161,449  

Adjustments to reconcile net income to net cash provided by (used in) operating activities

                                       

Depreciation, depletion and amortization

    148       42       98,656       —         98,846  

Distributed earning of unconsolidated affiliates

                                       

Earnings from unconsolidated affiliates

    —         (898 )     (10,475 )     —         (11,373 )

Distributions from unconsolidated affiliates

    —         —         12,140       —         12,140  

(Gain) loss on sale of long-lived assets

    (19,000 )     —         321       —         (18,679 )

Loss due to write-off of unamortized debt issuance costs, premiums and discounts

    11,320       —         1,224       —         12,544  

Amortization of debt issuance cost

    7,118       —         380       —         7,498  

Other noncash items

    1,224       1,206       1,015       —         3,445  

Working capital changes, net of acquisitions and non-cash transactions

    3,193       (533 )     (362 )     —         2,298  
   


 


 


 


 


Net cash provided by operating activities

    167,142       295       337,484       (236,753 )     268,168  
   


 


 


 


 


Cash flows from investing activities

                                       

Development expenditures for oil and natural gas properties

    —         —         (145 )     —         (145 )

Additions to property, plant and equipment

    (2,166 )     (19 )     (329,834 )     —         (332,019 )

Proceeds from the sale and retirement of assets

    69,836       —         8,075       —         77,911  

Proceeds from sale of investments in unconsolidated affiliates

    —         1,355       —         —         1,355  

Additions to investments in unconsolidated affiliates

    —         (211 )     (35,325 )     —         (35,536 )

Repayments on note receivable

    —         1,238       —         —         1,238  

Cash paid for acquisitions, net of cash acquired

    —         (20 )     —         —         (20 )
   


 


 


 


 


Net cash provided by (used in) investing activities

    67,670       2,343       (357,229 )     —         (287,216 )
   


 


 


 


 


Cash flows from financing activities:

                                       

Net proceeds from revolving credit facility

    533,564       —         —         —         533,564  

Repayments of revolving credit facility

    (647,000 )     —         —         —         (647,000 )

Net proceeds from senior secured acquisition term loan

    (23 )     —         —         —         (23 )

Repayment of senior secured acquisition term loan

    (237,500 )     —         —         —         (237,500 )

Repayment of GulfTerra Holding term loan

    —         —         (160,000 )     —         (160,000 )

Net proceeds from senior secured term loan

    299,512       —         —         —         299,512  

Repayment of senior secured term loan

    (160,000 )     —         —         —         (160,000 )

Net proceeds from issuance of long-term debt

    537,428       —         —         —         537,426  

Repayments of long-term debt

    (269,401 )     —         —         —         (269,401 )

Net proceeds from issuance of common units

    509,008       —         —         —         509,010  

Redemption of Series B preference units

    (155,673 )     —         —         —         (155,673 )

Advances with affiliates

    (399,780 )     (1,396 )     164,423       236,753       —    

Distributions to partners

    (238,397 )     —         —         —         (238,397 )

Distributions to minority interests

    —         (1,242 )     —         —         (1,242 )

Contribution from general partner

    3,098       —         —         —         3,098  
   


 


 


 


 


Net cash provided by (used in) financing activities

    (225,164 )     (2,638 )     4,423       236,753       13,374  
   


 


 


 


 


Increase (decrease) in cash and cash equivalents

  $ 9,648     $ —       $ (15,322 )   $ —         (5,674 )
   


 


 


 


       

Cash and cash equivalents at beginning of year

                                    36,099  
                                   


Cash and cash equivalents at end of year

                                  $ 30,425  
                                   


 

F-196


Table of Contents
Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOW

YEAR ENDED DECEMBER 31, 2002

 

    ISSUER

   

NON-GUARANTOR

SUBSIDIARIES(1)


   

GUARANTOR

SUBSIDIARIES


   

CONSOLIDATING

ELIMINATIONS


   

CONSOLIDATED

TOTAL


 
    (IN THOUSANDS)  

Cash flows from operating activities

                                       

Net income

  $ 97,688     $ 29,714     $ 64,851     $ (94,565 )   $ 97,688  

Less income from discontinued operations

    —         4,004       1,132       —         5,136  
   


 


 


 


 


Income from continuing operations

    97,688       25,710       63,719       (94,565 )     92,552  

Adjustments to reconcile net income to net cash provided by operating activities

                                       

Depreciation, depletion and amortization

    274       10,730       61,122       —         72,126  

Distributed earnings of unconsolidated affiliates

                                       

Earnings from unconsolidated affiliates

    —         —         (13,639 )     —         (13,639 )

Distributions from unconsolidated affiliates

    —         —         17,804       —         17,804  

Loss on sale of long-lived assets

    —         —         473       —         473  

Loss due to write-off of unamortized debt issuance costs, premiums and discounts

    —         —         2,434       —         2,434  

Amortization of debt issuance cost

    3,449       621       373       —         4,443  

Other noncash items

    1,053       1,942       1,434       —         4,429  

Working capital changes, net of acquisitions and non-cash transactions

    16,812       (21,676 )     (5,002 )     —         (9,866 )
   


 


 


 


 


Net cash provided by continuing operations

    119,276       17,327       128,718       (94,565 )     170,756  

Net cash provided by discontinued operations

    —         4,631       613       —         5,244  
   


 


 


 


 


Net cash provided by operating activities

    119,276       21,958       129,331       (94,565 )     176,000  
   


 


 


 


 


Cash flows from investing activities

                                       

Development expenditures for oil and natural gas properties

    —         —         (1,682 )     —         (1,682 )

Additions to property, plant and equipment

    (4,619 )     (9,099 )     (188,823 )     —         (202,541 )

Proceeds from the sale and retirement of assets

    —         —         5,460       —         5,460  

Additions to investments in unconsolidated affiliates

    —         (1,910 )     (36,365 )     —         (38,275 )

Cash paid for acquisitions, net of cash acquired

    —         (729,000 )     (435,856 )     —         (1,164,856 )
   


 


 


 


 


Net cash used in investing activities of continuing operations

    (4,619 )     (740,009 )     (657,266 )     —         (1,401,894 )

Net cash provided by (used in) investing activities of discontinued operations

    —         (3,523 )     190,000       —         186,477  
   


 


 


 


 


Net cash used in investing activities

    (4,619 )     (743,532 )     (467,266 )     —         (1,215,417 )
   


 


 


 


 


Cash flows from financing activities

                                       

Net proceeds from revolving credit facility

    359,219       7,000       —         —         366,219  

Repayments of revolving credit facility

    (170,000 )     (7,000 )     —         —         (177,000 )

Net proceeds from GulfTerra Holding term credit facility

    —         530,529       (393 )     —         530,136  

Repayment of GulfTerra Holding term credit facility

    —         (375,000 )     —         —         (375,000 )

Net proceeds from senior secured acquisition term loan

    233,236       —         —         —         233,236  

Net proceeds from senior secured term loan

    156,530       —         —         —         156,530  

Net proceeds from issuance of long-term debt

    423,528       —         —         —         423,528  

Repayment of Argo term loan

    —         —         (95,000 )     —         (95,000 )

Net proceeds from issuance of common units

    150,159       —         —         —         150,159  

Advances with affiliates

    (1,103,585 )     581,601       427,419       94,565       —    

Contributions from general partner

    4,095       —         —         —         4,095  

Distributions to partners

    (154,468 )     —         —         —         (154,468 )
   


 


 


 


 


Net cash provided by (used in) financing activities of continuing operations

    (101,286 )     737,130       332,026       94,565       1,062,435  

Net cash used in financing activities of discontinued operations

    —         (3 )     —         —         (3 )
   


 


 


 


 


Net cash provided by (used in) financing activities

    (101,286 )     737,127       332,026       94,565       1,062,432  
   


 


 


 


 


Increase (decrease) in cash and cash equivalents

  $ 13,371     $ 15,553     $ (5,909 )   $ —         23,015  
   


 


 


 


       

Cash and cash equivalents at beginning of year

                                    13,084  
                                   


Cash and cash equivalents at end of year

                                  $ 36,099  
                                   



(1) Non-guarantor subsidiaries consisted of Argo and Argo I for the quarter ended March 31, 2002; EPN Holding subsidiaries for the quarters ended June 30, 2002 and September 30, 2002; and our unrestricted subsidiaries for the quarter ended December 31, 2002.

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW

YEAR ENDED DECEMBER 31, 2001

 

    ISSUER

   

NON-GUARANTOR

SUBSIDIARIES(1)


   

GUARANTOR

SUBSIDIARIES


   

CONSOLIDATING

ELIMINATIONS


   

CONSOLIDATED

TOTAL


 
    (IN THOUSANDS)  

Cash flows from operating activities

                                       

Net income

  $ 55,149     $ 1,308     $ 22,393     $ (23,701 )   $ 55,149  

Less income from discontinued operations

    —         1,308       (211 )     —         1,097  
   


 


 


 


 


Income from continuing operations

    55,149       —         22,604       (23,701 )     54,052  

Adjustments to reconcile net income to net cash provided by operating activities

                                       

Depreciation, depletion and amortization

    323       —         34,455       —         34,778  

Asset impairment charge

    —         —         3,921       —         3,921  

Distributed earnings of unconsolidated affiliates

                                       

Earnings from unconsolidated affiliates

    —         —         (8,449 )     —         (8,449 )

Distributions from unconsolidated affiliates

    —         —         35,062       —         35,062  

Loss on sales of long-lived assets

    10,941       —         426       —         11,367  

Amortization of debt issuance cost

    3,290       318       —         —         3,608  

Other noncash items

    270       —         274       —         544  

Working capital changes, net of effects of acquisitions and non-cash transactions

    (10,145 )     385       (42,707 )     —         (52,467 )
   


 


 


 


 


Net cash provided by continuing operations

    59,828       703       45,586       (23,701 )     82,416  

Net cash provided by discontinued operations

    —         4,296       672       —         4,968  
   


 


 


 


 


Net cash provided by operating activities

    59,828       4,999       46,258       (23,701 )     87,384  
   


 


 


 


 


Cash flows from investing activities

                                       

Development expenditures for oil and natural gas properties

    —         —         (2,018 )     —         (2,018 )

Additions to property, plant and equipment

    (896 )     —         (507,451 )     —         (508,347 )

Proceeds from the sale and retirement of assets

    89,162       —         19,964       —         109,126  

Additions to investments in unconsolidated affiliates

    —         —         (1,487 )     —         (1,487 )

Cash paid for acquisitions, net of cash acquired

    —         —         (28,414 )     —         (28,414 )
   


 


 


 


 


Net cash provided by (used in) investing activities of continuing operations

    88,266       —         (519,406 )     —         (431,140 )

Net cash used in investing activities of discontinued operations

    —         (67,367 )     (1,193 )     —         (68,560 )
   


 


 


 


 


Net cash provided by (used in) investing activities

    88,266       (67,367 )     (520,599 )     —         (499,700 )
   


 


 


 


 


Cash flows from financing activities

                                       

Net proceeds from revolving credit facility

    559,994       —         —         —         559,994  

Repayments of revolving credit facility

    (581,000 )     —         —         —         (581,000 )

Net proceeds from issuance of long-term debt

    243,032       —         —         —         243,032  

Advances with affiliates

    (515,198 )     13,563       477,934       23,701       —    

Net proceeds from issuance of common units

    286,699       —         —         —         286,699  

Redemption of Series B preference units

    (50,000 )     —         —         —         (50,000 )

Contributions from general partner

    2,843       —         —         —         2,843  

Distributions to partners

    (105,923 )     —         (486 )     —         (106,409 )
   


 


 


 


 


Net cash provided by (used in) financing activities of continuing operations

    (159,553 )     13,563       477,448       23,701       355,159  

Net cash provided by financing activities of discontinued operations

    —         49,960       —         —         49,960  
   


 


 


 


 


Net cash provided by (used in) financing activities

    (159,553 )     63,523       477,448       23,701       405,119  
   


 


 


 


 


Increase (decrease) in cash and cash equivalents

  $ (11,459 )   $ 1,155     $ 3,107     $ —         (7,197 )
   


 


 


 


       

Cash and cash equivalents at beginning of year

                                    20,281  
                                         

Cash and cash equivalents at end of year

                                  $ 13,084  
                                   



(1) Non-guarantor subsidiaries consist of Argo and Argo I, which were formed in August 2000.

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

17. SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED):

 

General

 

This footnote discusses our oil and natural gas production activities for the year 2001. The years 2003 and 2002 are not presented since these operations are not a significant part of our business as defined by SFAS No. 69, Disclosures About Oil and Gas Producing Activities, and we do not expect it to become significant in the future.

 

Oil and Natural Gas Reserves

 

The following table represents our net interest in estimated quantities of proved developed and proved undeveloped reserves of crude oil, condensate and natural gas and changes in such quantities at year end 2001. Estimates of our reserves at December 31, 2001 have been made by the independent engineering consulting firm, Netherland, Sewell & Associates, Inc. except for the Prince Field for 2001, which was prepared by El Paso Production Company, our affiliate and operator of the Prince Field. Net proved reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our policy is to recognize proved reserves only when economic producibility is supported by actual production. As a result, no proved reserves were booked with respect to any of our producing fields in the absence of actual production. Proved developed reserves are proved reserve volumes that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserve volumes that are expected to be recovered from new wells on undrilled acreage or from existing wells where a significant expenditure is required for recompletion. Reference Rules 4-10(a)(2)(i), (ii), (iii), (3) and (4) of Regulation S-X, for detailed definitions of proved reserves, which can be found at the SEC’s website, http://www.sec.gov/divisions/corpfin/forms/regsx.htm#gas.

 

Estimates of reserve quantities are based on sound geological and engineering principles, but, by their very nature, are still estimates that are subject to substantial upward or downward revision as additional information regarding producing fields and technology becomes available.

 

    

OIL/CONDENSATE

MBBLS(1)


   

NATURAL GAS

MMCF(1)


 

Proved reserves—December 31, 2000

   1,201     11,500  

Revision of previous estimates

   1,852     5,913  

Production(2)

   (345 )   (4,172 )
    

 

Proved reserves—December 31, 2001

   2,708     13,241  
    

 

Proved developed reserves

            

December 31, 2001(2)

   2,350     10,384  

(1) Includes our overriding royalty interest in proved reserves on Garden Banks Block 73 and the Prince Field.
(2) Includes our overriding royalty interest in proved reserves of 1,341 MBbls of oil and 1,659 MMcf of natural gas on our Prince Field, which began production in 2001. These reserves were not included in proved reserves prior to 2001 because, consistent with our policy, economic producibility had not been supported by actual production. Also, we had increases in estimated proved reserves relating to our producing properties, primarily at our West Delta 35 field. Actual production in the Prince Field for 2001 was 37 MBbls of oil and 32 MMcf of natural gas.

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following are estimates of our total proved developed and proved undeveloped reserves of oil and natural gas by producing property as of December 31, 2001.

 

     OIL (BARRELS)

   NATURAL GAS (MCF)

    

PROVED

DEVELOPED


  

PROVED

UNDEVELOPED


  

PROVED

DEVELOPED


  

PROVED

UNDEVELOPED


     (IN THOUSANDS)

Garden Banks Block 72

   277    —      1,900    —  

Garden Banks Block 117

   1,065    —      1,556    —  

Viosca Knoll Block 817

   12    —      2,216    2,437

West Delta Block 35

   13    —      3,473    —  

Prince Field

   983    358    1,239    420
    
  
  
  

Total

   2,350    358    10,384    2,857
    
  
  
  

 

In general, estimates of economically recoverable oil and natural gas reserves and of the future net revenue therefrom are based upon a number of variable factors and assumptions, such as historical production from the subject properties, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs and future plugging and abandonment costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net revenue expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. The meaningfulness of such estimates is highly dependent upon the assumptions upon which they are based.

 

Estimates with respect to proved undeveloped reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than upon actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. A significant portion of our reserves is based upon volumetric calculations.

 

Future Net Cash Flows

 

The standardized measure of discounted future net cash flows relating to our proved oil and natural gas reserves is calculated and presented in accordance with SFAS No. 69. Accordingly, future cash inflows were determined by applying year-end oil and natural gas prices, as adjusted for fixed price contracts in effect, to our estimated share of future production from proved oil and natural gas reserves. The average prices utilized in the calculation of the standardized measure of discounted future net cash flows at December 31, 2001, were $16.75 per barrel of oil and $2.62 per Mcf of natural gas. Actual future prices and costs may be materially higher or lower. Future production and development costs were computed by applying year-end costs to future years. As we are not a taxable entity, no future income taxes were provided. A prescribed 10 percent discount factor was applied to the future net cash flows.

 

In our opinion, this standardized measure is not a representative measure of fair market value, and the standardized measure presented for our proved oil and natural gas reserves is not representative of the reserve value. The standardized measure is intended only to assist financial statement users in making comparisons between companies. In the table following, the amounts of future production costs have been restated to include

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

platform access fees paid to our platform segment. See note 2 to the table for further discussion of the impact of such fees on our consolidated standardized measure of discounted future net cash flows.

 

    

DECEMBER 31,

2001


 
     (IN THOUSANDS)  

Future cash inflows(1)

   $ 80,603  

Future production costs(2)

     (19,252 )

Future development costs

     (10,530 )
    


Future net cash flows

     50,821  

Annual discount at 10% rate

     (11,761 )
    


Standardized measure of discounted future net cash flows

   $ 39,060  
    



(1) Our future cash inflows include estimated future receipts from our overriding royalty interest in our Prince Field and Garden Banks Block 73. Since these are overriding royalty interests, we do not participate in the production or development costs for these fields, but do include their proved reserves, production volumes and future cash inflows in our data.
(2) Our future production costs include platform access fees paid by our oil and natural gas production business to affiliated entities included in our platform services segment. Such platform access fees are eliminated in our consolidated financial statements. The future platform access fees paid to our platform segment were $4,960 for 2001. On a consolidated basis, our standardized measure of discounted future net cash flows was $43,789 for 2001.

 

Estimated future net cash flows for proved developed and proved undeveloped reserves as of December 31, 2001, are as follows:

 

    

PROVED

DEVELOPED


  

PROVED

UNDEVELOPED


   TOTAL

     (IN THOUSANDS)

Undiscounted estimated future net cash flows from proved reserves before income taxes

   $ 40,518    $ 10,303    $ 50,821
    

  

  

Present value of estimated future net cash flows from proved reserves before income taxes, discounted at 10%

   $ 31,003    $ 8,057    $ 39,060
    

  

  

 

The following are the principal sources of change in the standardized measure:

 

     2001

 
     (IN THOUSANDS)  

Beginning of year

   $ 77,706  

Sales and transfers of oil and natural gas produced, net of production costs

     (34,834 )

Net changes in prices and production costs

     (55,657 )

Extensions, discoveries and improved recovery, less related costs

     —    

Oil and natural gas development costs incurred during the year

     2,018  

Changes in estimated future development costs

     535  

Revisions of previous quantity estimates

     38,090  

Accretion of discount

     7,771  

Changes in production rates, timing and other

     3,431  
    


End of year

   $ 39,060  
    


 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Development, Exploration, and Acquisition Expenditures

 

The following table details certain information regarding costs incurred in our development, exploration, and acquisition activities during the year ended December 31:

 

     2001

     (IN THOUSANDS)

Development costs

   $ 2,018

Capitalized interest

     —  
    

Total capital expenditures

   $ 2,018
    

 

In the year presented, we elected not to incur any costs to develop our proved undeveloped reserves.

 

Capitalized Costs

 

Capitalized costs relating to our natural gas and oil producing activities and related accumulated depreciation, depletion and amortization were as follows as of December 31:

 

     2001

     (IN THOUSANDS)

Oil and natural gas properties

      

Proved properties

   $ 54,609

Wells, equipment, and related facilities

     104,766
    

       159,375

Less accumulated depreciation, depletion and amortization

     108,307
    

     $ 51,068
    

 

Results of operations

 

Results of operations from producing activities were as follows at December 31:

 

     2001

     (IN THOUSANDS)

Natural gas sales

   $ 18,248

Oil, condensate, and liquid sales

     8,062
    

Total operating revenues

     26,310

Production costs(1)

     16,367

Depreciation, depletion and amortization

     7,567
    

Results of operations from producing activities

   $ 2,376
    


(1) These production costs include platform access fees paid to affiliated entities included in our platform services segment. Such platform access fees, which were approximately $10 million in the year presented, are eliminated in our consolidated financial statements.

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

18. SUPPLEMENTAL QUARTERLY FINANCIAL INFORMATION:

 

     QUARTER ENDED (UNAUDITED)

     MARCH 31

   JUNE 30

   SEPTEMBER 30

   DECEMBER 31

    YEAR

     (IN THOUSANDS, EXCEPT PER UNIT DATA)

2003

                                   

Operating revenues(1)

   $ 230,095    $ 237,031    $ 213,831    $ 190,532     $ 871,489

Operating income

     75,107      77,886      92,079      69,391       314,463

Income from continuing operations

     40,525      49,297      60,213      11,414       161,449

Cumulative effect of accounting change

     1,690      —        —        —         1,690
    

  

  

  


 

Net income

     42,215      49,297      60,213      11,414       163,139

Income allocation

                                   

Series B unitholders

   $ 3,876    $ 3,898    $ 4,018    $ —       $ 11,792
    

  

  

  


 

General partner

                                   

Income from continuing operations

   $ 14,860    $ 15,856    $ 18,031    $ 20,667     $ 69,414

Cumulative effect of accounting change

     17      —        —        —         17
    

  

  

  


 

     $ 14,877    $ 15,856    $ 18,031    $ 20,667     $ 69,431
    

  

  

  


 

Common unitholders

                                   

Income from continuing operations

   $ 17,454    $ 24,160    $ 31,337    $ (7,796 )   $ 65,155

Cumulative effect of accounting change

     1,340      —        —        —         1,340
    

  

  

  


 

     $ 18,794    $ 24,160    $ 31,337    $ (7,796 )   $ 66,495
    

  

  

  


 

Series C unitholders

                                   

Income from continuing operations

   $ 4,335    $ 5,383    $ 6,827    $ (1,457 )   $ 15,088

Cumulative effect of accounting change

     333      —        —        —         333
    

  

  

  


 

     $ 4,668    $ 5,383    $ 6,827    $ (1,457 )   $ 15,421
    

  

  

  


 

Basic earnings per common unit

                                   

Income from continuing operations

   $ 0.40    $ 0.50    $ 0.63    $ (0.14 )   $ 1.30

Cumulative effect of accounting change

     0.03      —        —        —         0.03
    

  

  

  


 

Net income

   $ 0.43    $ 0.50    $ 0.63    $ (0.14 )   $ 1.33
    

  

  

  


 

Diluted earnings per common unit(2)

                                   

Income from continuing operations

   $ 0.40    $ 0.50    $ 0.62    $ (0.14 )   $ 1.30

Cumulative effect of accounting change

     0.03      —        —        —         0.02
    

  

  

  


 

Net income

   $ 0.43    $ 0.50    $ 0.62    $ (0.14 )   $ 1.32
    

  

  

  


 

Distributions declared and paid per common unit

   $ 0.675    $ 0.675    $ 0.700    $ 0.710     $ 2.760
    

  

  

  


 

Basic weighted average number of common units outstanding

     44,104      48,005      50,072      57,562       49,953
    

  

  

  


 

Diluted weighted average number of common units outstanding

     44,104      48,476      50,385      57,855       50,231
    

  

  

  


 


(1) Since November 2002, when we acquired the Typhoon Oil Pipeline, we have recognized revenue attributable to it using the “gross” method, which means we record as “revenues” all oil that we purchase from our customers at an index price less an amount that compensates us for our service and we record as “cost of oil” that same oil which we resell to those customers at the index price. We believe that a “net” presentation is more appropriate than a “gross” presentation and is consistent with how we evaluate the performance of the Typhoon Oil Pipeline. Based on our review of the accounting literature, we believe that generally accepted accounting principles permit us to use the “net” method, and accordingly we have presented the results of Typhoon Oil “net” for all periods. To reflect this reclassification, operating revenues have been reduced by $48.8 million, $73.1 million and $69.8 million for the quarters ended March 31, June 30 and September 30 of 2003. This change does not affect operating income or net income.
(2) As a result of the loss allocated to our common unitholders during the quarter ended December 31, 2003, the basic and diluted earnings per common units are the same.

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

     QUARTER ENDED (UNAUDITED)

     MARCH 31

   JUNE 30

   SEPTEMBER 30

   DECEMBER 31

   YEAR

     (IN THOUSANDS, EXCEPT PER UNIT DATA)

2002

                                  

Operating revenues(1)

   $ 61,544    $ 120,489    $ 122,249    $ 153,108    $ 457,390

Operating income

     22,712      45,777      41,936      50,385      160,810

Income from continuing operations

     14,741      28,685      23,346      25,780      92,552

Income from discontinued operations

     4,385      60      456      235      5,136
    

  

  

  

  

Net income

     19,126      28,745      23,802      26,015      97,688

Income allocation

                                  

Series B unitholders

   $ 3,552    $ 3,630    $ 3,693    $ 3,813    $ 14,688
    

  

  

  

  

General partner

                                  

Income from continuing operations

   $ 8,691    $ 10,799    $ 10,755    $ 11,837    $ 42,082

Income from discontinued operations

     44      —        5      2      51
    

  

  

  

  

     $ 8,735    $ 10,799    $ 10,760    $ 11,839    $ 42,133
    

  

  

  

  

Common unitholders

                                  

Income from continuing operations

   $ 2,498    $ 14,256    $ 8,898    $ 8,623    $ 34,275

Income from discontinued operations

     4,341      60      451      233      5,085
    

  

  

  

  

     $ 6,839    $ 14,316    $ 9,349    $ 8,856    $ 39,360
    

  

  

  

  

Series C unitholders

   $ —      $ —      $ —      $ 1,507    $ 1,507
    

  

  

  

  

Basic and diluted earnings per common unit

                                  

Income from continuing operations

   $ 0.06    $ 0.33    $ 0.20    $ 0.21    $ 0.80

Income from discontinued operations

     0.11      —        0.01      —        0.12
    

  

  

  

  

Net income

   $ 0.17    $ 0.33    $ 0.21    $ 0.21    $ 0.92
    

  

  

  

  

Distributions declared and paid per common unit

   $ 0.625    $ 0.650    $ 0.650    $ 0.675    $ 2.600
    

  

  

  

  

Weighted average number of common units outstanding

     39,941      42,842      44,130      44,069      42,814
    

  

  

  

  


(1) Operating revenues for the quarter ended December 31, 2002, have been reduced by $10.5 million to reflect the reclassification of Typhoon Oil Pipeline’s cost of oil.

 

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Index to Financial Statements

Report of Independent Registered Public Accounting Firm

 

To the Members of Poseidon Oil Pipeline Company, L.L.C.:

 

In our opinion, the accompanying balance sheets and the related statements of income, members’ capital, comprehensive income and changes in accumulated other comprehensive income and cash flows present fairly, in all material respects, the financial position of Poseidon Oil Pipeline Company, L.L.C. (the “Company”) at December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

As discussed in Note 1 to the financial statements, the Company has restated its statements of income and cash flows for the years ended December 31, 2002 and 2001, and its balance sheet as of December 31, 2002.

 

/s/    PricewaterhouseCoopers LLP

 

Houston, Texas

March 17, 2004

 

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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

STATEMENTS OF INCOME

(IN THOUSANDS)

 

     FOR THE YEARS ENDED DECEMBER 31,

 
           2003      

          2002      

          2001      

 
           (RESTATED)     (RESTATED)  

Operating revenues

                        

Crude oil handling revenues

   $ 42,573     $ 55,490     $ 70,676  

Other, net

     450       939       1,331  
    


 


 


Total revenues

     43,023       56,429       72,007  
    


 


 


Operating expenses

                        

Crude oil handling costs

     2,579       2,168       1,115  

Operation and maintenance

     3,694       4,691       2,077  

Depreciation and amortization

     8,316       8,356       10,552  
    


 


 


       14,589       15,215       13,744  
    


 


 


Operating income

     28,434       41,214       58,263  

Other income (expense)

                        

Interest income

     56       95       394  

Interest and debt expense

     (5,464 )     (6,923 )     (7,668 )

Other income

     —         26,600       —    
    


 


 


Net income

   $ 23,026     $ 60,986     $ 50,989  
    


 


 


 

 

 

See accompanying notes.

 

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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

BALANCE SHEETS

AS OF DECEMBER 31, 2003 AND 2002

(IN THOUSANDS)

 

     2003

   2002

 
     (RESTATED)  
ASSETS                

Current assets

               

Cash and cash equivalents

   $ 7,950    $ 27,606  

Accounts receivable

               

Trade

     3,396      14,040  

Affiliate

     1,914      2,144  

Unbilled

     4,354      3,614  

Other current assets

     3,282      2,390  
    

  


Total current assets

     20,896      49,794  

Property, plant and equipment, net

     215,195      214,497  

Debt reserve fund

     3,576      3,551  

Other noncurrent assets

     122      415  
    

  


Total assets

   $ 239,789    $ 268,257  
    

  


LIABILITIES AND MEMBERS’ CAPITAL                

Current liabilities

               

Accounts payable, trade

   $ 11,239    $ 10,423  

Accounts payable, affiliate

     1,866      5,176  

Interest rate hedge liabilities

     —        1,385  
    

  


Total current liabilities

     13,105      16,984  

Revolving credit facility

     123,000      148,000  

Commitments and contingencies

               

Members’ capital

               

Members’ capital before accumulated other comprehensive income

     103,684      104,658  

Accumulated other comprehensive income

     —        (1,385 )
    

  


Total members’ capital

     103,684      103,273  
    

  


Total liabilities and members’ capital

   $ 239,789    $ 268,257  
    

  


 

 

See accompanying notes.

 

F-207


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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

STATEMENTS OF CASH FLOWS

(IN THOUSANDS)

 

     FOR THE YEARS ENDED DECEMBER 31,

 
           2003      

          2002      

          2001      

 
           (RESTATED)     (RESTATED)  

Cash flows from operating activities

                        

Net income

   $ 23,026     $ 60,986     $ 50,989  

Adjustments to reconcile net income to cash provided by operating activities

                        

Depreciation and amortization

     8,316       8,356       10,552  

Amortization of debt issue costs

     293       293       186  

Changes in operating assets and liabilities

                        

(Increase) decrease in accounts receivable

     10,134       (2,615 )     (5,006 )

(Increase) decrease in other current assets

     (892 )     96       99  

Increase (decrease) in accounts payable

     (2,494 )     5,837       3,017  

Decrease in reserve for revenue refund

     —         —         (1,297 )
    


 


 


Net cash provided by operating activities

     38,383       72,953       58,540  
    


 


 


Cash flows from investing activities

                        

Capital expenditures

     (9,014 )     (3,890 )     (124 )

Proceeds from sale of assets

     —         3,400       —    

(Increase) decrease in debt reserve fund

     (25 )     (52 )     2,740  
    


 


 


Net cash provided by (used in) investing activities

     (9,039 )     (542 )     2,616  
    


 


 


Cash flows from financing activities

                        

Repayments of long-term debt

     (25,000 )     (2,000 )     —    

Debt issue costs

     —         —         (894 )

Distributions to partners

     (24,000 )     (43,900 )     (61,699 )
    


 


 


Net cash used in financing activities

     (49,000 )     (45,900 )     (62,593 )
    


 


 


Increase (decrease) in cash and cash equivalents

     (19,656 )     26,511       (1,437 )

Cash and cash equivalents:

                        

Beginning of period

     27,606       1,095       2,532  
    


 


 


End of period

   $ 7,950     $ 27,606     $ 1,095  
    


 


 


Supplemental disclosure of cash flow information

                        

Cash paid for interest, net of amounts capitalized

   $ 5,034     $ 5,959     $ 6,423  
    


 


 


 

See accompanying notes.

 

F-208


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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

STATEMENTS OF MEMBERS’ CAPITAL

FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001

(IN THOUSANDS)

 

    

POSEIDON PIPELINE

COMPANY, L.L.C.

(36%)


   

SHELL OIL

PRODUCTS U.S.

(36%)


   

MARATHON OIL

COMPANY

(28%)


    TOTAL

 

Balance at January 1, 2001

   $ 35,381     $ 35,381     $ 27,520     $ 98,282  

Cash distributions

     (22,212 )     (22,212 )     (17,275 )     (61,699 )

Net income

     18,356       18,356       14,277       50,989  
    


 


 


 


Balance at December 31, 2001

     31,525       31,525       24,522       87,572  

Cash distributions

     (15,804 )     (15,804 )     (12,292 )     (43,900 )

Net income

     21,955       21,955       17,076       60,986  

Other comprehensive loss

     (498 )     (498 )     (389 )     (1,385 )
    


 


 


 


Balance at December 31, 2002

     37,178       37,178       28,917       103,273  

Cash distributions

     (8,640 )     (8,640 )     (6,720 )     (24,000 )

Net income

     8,289       8,289       6,448       23,026  

Other comprehensive income

     498       498       389       1,385  
    


 


 


 


Balance at December 31, 2003

   $ 37,325     $ 37,325     $ 29,034     $ 103,684  
    


 


 


 


 

See accompanying notes.

 

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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

STATEMENTS OF COMPREHENSIVE INCOME AND

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(IN THOUSANDS)

 

     FOR THE YEARS ENDED DECEMBER 31,

             2003        

            2002        

            2001        

COMPREHENSIVE INCOME

                      

Net income

   $ 23,026     $ 60,986     $ 50,989

Other comprehensive income (loss)

     1,385       (1,385 )     —  
    


 


 

Total comprehensive income

   $ 24,411     $ 59,601     $ 50,989
    


 


 

ACCUMULATED OTHER COMPREHENSIVE INCOME

                      

Beginning balance

   $ (1,385 )   $ —       $ —  

Unrealized net gain (loss) from interest rate swap

     1,385       (1,385 )     —  
    


 


 

Ending balance

   $ —       $ (1,385 )   $ —  
    


 


 

ACCUMULATED OTHER COMPREHENSIVE LOSS ALLOCATED TO:

                      

Poseidon Pipeline Company, L.L.C

   $ —       $ (498 )   $ —  

Shell Oil Products U.S

     —         (498 )     —  

Marathon Oil Company

     —         (389 )     —  
    


 


 

     $ —       $ (1,385 )   $ —  
    


 


 

 

See accompanying notes.

 

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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

NOTES TO FINANCIAL STATEMENTS

 

NOTE 1—ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

 

Poseidon Oil Pipeline Company, L.L.C. is a Delaware limited liability company, formed in February 1996, to design, construct, own and operate the unregulated Poseidon Pipeline extending from the Gulf of Mexico to onshore Louisiana.

 

Our members are Shell Oil Products U.S. (Shell), Poseidon Pipeline Company, L.L.C. (Poseidon), a subsidiary of GulfTerra Energy Partners, L.P. (formerly El Paso Energy Partners, L.P.), and Marathon Pipeline Company (Marathon), which own 36 percent, 36 percent, and 28 percent in us.

 

Manta Ray Gathering Company, L.L.C., a subsidiary of GulfTerra Energy Partners, L.P., and an affiliate of ours, is our operator.

 

The terms “we,” “our” or “us”, as used in these notes to financial statements, refer to Poseidon Oil Pipeline Company, L.L.C.

 

We are in the business of providing crude oil handling services in the Gulf of Mexico. We provide these services in accordance with various purchase and sale contracts with producers served by our pipeline. We buy crude oil at various points along the pipeline and resell the crude oil at a destination point in accordance with each individual contract. Our margin from these purchase and sale agreements is earned based upon the differential between the sales price and the purchase price and represents our earnings from providing handling services. Differences between measured purchased and sold volumes in any period are recorded as changes in exchange imbalances with producers.

 

Basis of Presentation

 

Our financial statements are prepared on the accrual basis of accounting in conformity with accounting principles generally accepted in the United States. Our financial statements for previous periods include reclassifications that were made to conform to the current year presentation. Those reclassifications have no impact on reported net income or members’ capital.

 

Restatement of Financial Statements

 

We have restated our previously reported financial statements as of December 31, 2002 and for the years ended December 31, 2002 and 2001. These restatements had no effect on previously reported operating income, net income or total members’ capital.

 

For the years ended December 31, 2002 and 2001, we have restated our crude oil handing revenues and our crude oil handling costs in our statements of income to reflect the net amounts we earn for handling services, rather than the gross amounts of oil purchased and sold under our buy/sell contracts with producers. We have also restated our accounts receivable and accounts payable balances at December 31, 2002, to give effect to this change and restated the amounts for changes in operating assets and liabilities in our statements of cash flows for the years ended December 31, 2002 and 2001. These restatements had no effect on net cash provided by operating activities. Additionally, we have reclassified the change in our debt reserve fund from a financing activity to an investing activity in our statements of cash flows for the years ended December 31, 2002 and 2001.

 

F-211


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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

The effects of these changes on our previously reported financial statements for the years ended December 31, 2002 and 2001, and as of December 31, 2002 are presented below.

 

     2002

    2001

 
    

AS

PREVIOUSLY

REPORTED


   

AS

RESTATED


   

AS

PREVIOUSLY

REPORTED


   

AS

RESTATED


 
     (IN THOUSANDS)  

Statements of Income

                                

Crude oil handling revenue

   $ 1,086,757     $ 55,490     $ 1,196,840     $ 70,676  

Other revenue net(1)

     —         939       —         1,331  

Crude oil handing costs

     1,032,496       2,168       1,126,439       1,115  

Operation and maintenance

     4,691       4,691       1,586       2,077  

Statements of Cash Flows

                                

(Increase) decrease in accounts receivable

     (30,141 )     (2,615 )     27,561       (5,006 )

Increase (decrease) in accounts payable

     33,363       5,837       (29,550 )     3,017  

Net cash provided by (used in) investing activities

     (490 )     (542 )     (124 )     2,616  

Net cash used in financing activities

     (45,952 )     (45,900 )     (59,853 )     (62,593 )

Balance Sheet

                                

Accounts receivable

                                

Trade

     92,646       14,040                  

Affiliate

     30,142       2,144                  

Unbilled(2)

     —         3,614                  

Accounts payable

                                

Trade

     84,191       10,423                  

Affiliate

     34,398       5,176                  

(1) In prior years, we had not separately reported net results of the sales and purchases related to pipeline allowance for losses. We have reclassified these amounts to conform to our 2003 presentation.
(2) In prior years, we had not separately reported unbilled accounts receivable from trade accounts receivable. We have reclassified this amount in our 2002 balance sheet to conform to our 2003 presentation.

 

Cash and Cash Equivalents

 

We consider short-term investments with little risk of change in value because of changes in interest rates and purchased with an original maturity of less than three months to be considered cash equivalents.

 

Debt Reserve Fund

 

In connection with our revolving credit facility, we are required to maintain a debt reserve account as collateral on the outstanding balances. At December 31, 2003 and 2002, the balance in the account was approximately $3.6 million and $3.6 million, and consisted of funds earning interest at 0.7% and 1.5%.

 

Allowance for Doubtful Accounts

 

Collectibility of accounts receivable is reviewed regularly and an allowance is recorded as necessary, primarily under the specific identification method. At December 31, 2003 and 2002, no allowance for doubtful accounts was recorded.

 

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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

Property, Plant and Equipment

 

Contributed property, plant and equipment is recorded at fair value as agreed to by the members at the date of contribution. Acquired property, plant and equipment is recorded at cost. Pipeline equipment is depreciated using a composite, straight-line method over the estimated useful lives of 3 to 30 years. Line-fill is not depreciated, as our management believes the cost of all barrels is fully recoverable. Repair and maintenance costs are expensed as incurred, while additions, improvements and replacements are capitalized. In addition, interest and other financing costs are capitalized in connection with construction as part of the cost of the asset and amortized over the related asset’s estimated useful life. No gain or loss is recognized on normal asset retirements under the composite method.

 

Impairment and Disposal of Long-Lived Assets

 

We apply the provisions of Statement of Financial Accounting Standards (SFAS) No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets to account for impairment and disposal of long-lived assets. Accordingly, we evaluate the recoverability of selected long-lived assets when adverse events or changes in circumstances indicate that the carrying value of an asset or group of assets may not be recoverable. We determine the recoverability of an asset or group of assets by estimating the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets at the lowest level for which separate cash flows can be measured. If the total of the undiscounted cash flows is less that the carrying amount for the assets, we estimate the fair value of the asset or group of assets and recognize the amount by which the carrying value exceeds the fair value, less cost to sell, as an impairment loss in income from operations in the period the impairment is determined. As provided by the provisions of SFAS No. 144, we adopted this standard on January 1, 2002, and our adoption did not have a material impact on our financial position or result of operations.

 

Additionally, as required by SFAS No. 144, we classify long-lived assets to be disposed of other than by sale (e.g., abandonment, exchange or distribution) as held and used until the item is abandoned, exchanged or distributed. We evaluate assets to be disposed of other than by sale for impairment and recognize a loss for the excess of the carrying value over the fair value. Long-lived assets to be disposed of through sale recognition meeting specific criteria are classified as “Held for Sale” and measured at the lower of their cost or fair value less cost to sell. We report the results of operations of a component classified as held for sale, including any gain or loss in the period(s) in which they occur.

 

Debt Issue Costs

 

Debt issue costs are capitalized and amortized over the life of the related indebtedness. Any unamortized debt issue costs are expensed at the time the related indebtedness is repaid or terminated. As of December 31, 2003 and 2002, debt issue costs of $122 thousand and $415 thousand are classified as an other noncurrent asset on our balance sheet. Amortization of debt issue costs is included in interest and debt expense on our consolidated statements of income.

 

Fair Value of Financial Instruments

 

The estimated fair values of our cash and cash equivalents, accounts receivable and accounts payable approximate their carrying amounts in the accompanying balance sheet due to the short-term maturity of these instruments. The fair value of our long-term debt with variable interest rates approximates its carrying value because of the market-based nature of the debt’s interest rates.

 

Revenue and Related Cost Recognition

 

We record crude oil handling revenue when we complete the delivery of crude oil to the agreed upon delivery point. In addition, we receive an allowance for losses of crude oil during the handling process. To the

 

F-213


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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

extent our actual losses are less than the allowance, we sell this excess oil and recognize revenue at the point of sale. To the extent our actual losses are greater than the allowance, we purchase oil to make-up the difference and record an expense at the point of purchase. We have presented the net results of the sales and purchases related to this pipeline allowance for losses as other, net in operating revenues.

 

Comprehensive Income

 

Our comprehensive income is determined based on net income (loss), adjusted for changes in accumulated other comprehensive income (loss) from our cash flow hedging activities associated with our interest rate hedge for our revolving credit facility.

 

Unbilled Accounts Receivable

 

Each month we record an estimate for our crude oil handling revenues and reflect the related receivables as unbilled accounts receivable. Accordingly, there is one month of estimated data recorded in our crude oil handling revenue and our accounts receivable for the years ended December 31, 2003, 2002 and 2001. Our estimate is based on actual volume and rate data through the first part of the month then extrapolated to the end of the month, adjusted according for any known or expected changes.

 

Crude Oil Imbalances

 

In the course of providing crude oil handling services for customers, we may receive quantities of crude oil that differ from the quantities committed to be delivered. These transactions result in imbalances that are settled in kind the following month. We value our imbalances based on the weighted average acquisition price of produced barrels for the current month. Our imbalance receivables and imbalance payables are classified on our balance sheet as accounts receivable and accounts payable as follows on December 31 (in thousands):

 

     2003

   2002

Imbalance Receivables

             

Trade

   $ 742    $ 2,123

Affiliates

   $ 263    $ 564

Imbalance Payables

             

Trade

   $ 2,066    $ 3,841

Affiliates

   $ 340    $ 3,927

 

Environmental Costs

 

Expenditures for ongoing compliance with environmental regulations that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and which do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated.

 

Accounting for Hedging Activities

 

We apply the provisions issued in SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities to account for price risk management activities. This statement requires us to measure all derivative instruments at their fair value, and classify them as either assets or liabilities on our balance sheet, with the

 

F-214


Table of Contents
Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

corresponding offset to income or other comprehensive income depending on their designation, their intended use, or their ability to qualify as hedges under the standard. In addition, we account for contracts entered into or modified after June 30, 2003, by applying the provisions of SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This statement amends SFAS No. 133 to incorporate several interpretations of the Derivatives Implementation Group (DIG), and also makes several minor modifications to the definition of a derivative as it was defined in SFAS No. 133. There was no initial financial statement impact of adopting this standard, although the FASB and DIG continue to deliberate on the application of the standard to certain derivative contracts, which may impact our financial statements in the future.

 

In January 2002, we entered into a two-year interest rate swap agreement with Credit Lyonnais to fix the variable LIBOR based interest rate on $75 million of our variable rate revolving credit facility at 3.49% through January 2004. Prior to April 2003, under our credit facility, we paid an additional 1.50% over the LIBOR rate resulting in an effective interest rate of 4.99% on the hedged notional amount. Beginning in April 2003, the additional interest we pay over LIBOR was reduced to 1.25% as a result of a decrease in our leverage ratio, resulting in an effective fixed interest rate of 4.74% on the hedged notional amount. Our interest rate swap expired on January 9, 2004. Collateral was not required and we do not anticipate non-performance by the counterparty.

 

Income Taxes

 

We are organized as a Delaware limited liability company and treated as a partnership for income tax purposes, and as a result, the income or loss resulting from our operations for income tax purposes is included in the federal and state tax returns of our members. Accordingly, no provision for income taxes has been recorded in the accompanying financial statements.

 

Management’s Use of Estimates

 

The preparation of our financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that effect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities that exist at the date of our financial statements. While we believe our estimates are appropriate, actual results can, and often do, differ from those estimates.

 

Income Allocation and Cash Distributions

 

Our income is allocated to our members based on their ownership percentages. At times, we may make cash distributions to our members in amounts determined by our Management Committee, which is responsible for conducting our affairs in accordance with our limited liability agreement.

 

Limitations of Member’s Liability

 

As a limited liability company, our members or their affiliates are not personally liable for any of our debts, obligations or liabilities simply because they are our members.

 

Business Combinations

 

We apply the provisions of SFAS No. 141, Business Combinations to account for business combinations. This statement requires that all transactions that fit the definition of a business combination be accounted for

 

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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

using the purchase method. This statement also established specific criteria for the recognition of intangible assets separately from goodwill and requires unallocated negative goodwill to be written off immediately as an extraordinary item.

 

Accounting for Asset Retirement Obligations

 

We apply the provisions of SFAS No. 143, Accounting for Asset Retirement Obligations to account for asset retirement obligations. This statement requires companies to record a liability for the estimated retirement and removal of assets used in their business. The liability is discounted to its present value, and the related asset value is increased by the amount of the resulting liability. Over the life of the asset, the liability will be accreted to its future value and eventually extinguished when the asset is taken out of service. Capitalized retirement and removal costs will be depreciated over the useful life of the related asset. As provided for by the provisions of SFAS No. 143, we adopted this standard on January 1, 2003 and our adoption of this statement did not have a material effect on our financial position or results of operations.

 

Reporting Gains and Losses from the Early Extinguishment of Debt

 

We apply the provisions of SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections to account for gains and losses from the early extinguishment of debt. Accordingly, we now evaluate the nature of any debt extinguishments to determine whether to report any gain or loss resulting from the early extinguishment of debt as an extraordinary item or as income from continuing operations.

 

Accounting for Costs Associated with Exit or Disposal Activities

 

We apply the provisions of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities to account for costs associated with exit or disposal activities. This statement impacts any exit or disposal activities that we initiate after January 1, 2003 and we now recognize costs associated with exit or disposal activities when they are incurred rather than when we commit to an exit or disposal plan. As provided for by the provisions of SFAS No. 143, we adopted this standard on January 1, 2003 and our adoption of this pronouncement did not have an effect on our financial position or results of operations.

 

Accounting for Guarantees

 

In accordance with the provisions of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, we record a liability at fair value, or otherwise disclose, certain guarantees issued after December 31, 2002, that contractually require us to make payments to a guaranteed party based on the occurrence of certain events. We do not currently guarantee the indebtedness of others; however the recognition, measurement and disclosure provisions of this interpretation will apply to any guarantees we may make in the future.

 

Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity

 

We apply the provisions of SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity to account for financial instruments with characteristics of both liabilities and equity. This statement provides guidance on the classification of financial instruments, as equity, as liabilities, or as both liabilities and equity. In accordance with the provisions of SFAS No. 150, we adopted this standard on July 1, 2003, and our adoption had no material impact on our financial statements.

 

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POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

NOTE 2—PROPERTY, PLANT AND EQUIPMENT

 

Our property, plant and equipment consisted of the following:

 

     DECEMBER 31,

 
     2003

    2002

 
     (IN THOUSANDS)  

Pipeline and equipment, at cost

   $ 265,496     $ 264,903  

Construction work in progress

     9,363       942  
    


 


       274,859       265,845  

Less accumulated depreciation

     (59,664 )     (51,348 )
    


 


Total property, plant and equipment, net

   $ 215,195     $ 214,497  
    


 


 

During 2003, we capitalized interest costs of $6,500 into property, plant and equipment. During 2002, we did not capitalize interest costs into property, plant and equipment.

 

NOTE 3—LONG-TERM DEBT

 

As of December 31, 2003 and 2002, we had $123 million and $148 million outstanding under our $185 million revolving credit facility that matures in April 2004 with the full unused amount available. The average variable floating interest rate was 2.5% and 3.4% at December 31, 2003 and 2002. We pay a variable commitment fee on the unused portion of the credit facility. The fair value of our revolving credit facility with variable interest rates approximates its carrying value because of the market based nature of our debt’s interest rates.

 

In January 2004, we amended our credit agreement and decreased the availability to $170 million. The amended facility matures in January 2008. The outstanding balance from the previous facility was transferred to the new facility.

 

Under our amended credit facility, our interest rate is LIBOR plus 2.00% for Eurodollar loans and a variable base rate equal to the greater of the prime rate or 0.50% plus the federal funds rate (as those terms are defined in our credit agreement) plus 1.00% for Base Rate loans as defined in our credit agreement. Our interest rates will decrease by 0.25% if our leverage ratio declines to 3.00 to 1.00 or less, by 50% if our leverage ratio declines to 2.00 to 1.00 or less, or by 0.625% if our leverage ratio declines to 1.00 to 1.00 or less. Additionally, we pay commitment fees on the unused portion of the credit facility at rates that vary from 0.25% to 0.375%. This credit agreement requires us to maintain a debt service reserve equal to two times the previous quarters’ interest.

 

Our revolving credit facility contains covenants such as restrictions on debt levels, restrictions on liens collateralizing debt and guarantees, restrictions on mergers and on the sales of assets and dividend restrictions. A breach of any of these covenants could result in acceleration of our debt and other financial obligations.

 

Under our $170 million revolving credit facility, the financial debt covenants are:

 

(a) we must maintain consolidated tangible net worth in an amount not less than $75 million plus 100% of the net cash proceeds from our issuance of equity securities of any kind;

 

(b) the ratio of earnings before interest, income taxes, depreciation and amortization (EBITDA), as defined in our credit facility, to interest expense paid or accrued during the four quarters ending on the last day of the current quarter must be at least 2.50 to 1.00; and

 

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POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

(c) the ratio of our total indebtedness to earnings before interest, income taxes, depreciation and amortization (EBITDA), as defined in our credit facility, for the four quarters ending on the last day of the current quarter shall not exceed 4.50 to 1.00 in 2004, 3.50 to 1.00 in 2005 and 3.00 to 1.00 thereafter.

 

We are in compliance with the above covenants as of the date of this report.

 

We use interest rate swaps to limit our exposure to fluctuations in interest rates. These interest rate swaps are accounted for in accordance with SFAS No. 133. In January 2004, the two-year interest rate swap to fix the variable LIBOR based interest rate on $75 million of our revolving facility at 3.49% expired. As of December 31, 2002, the fair value of our interest rate swap was a liability of $1.4 million resulting in accumulated other comprehensive loss of $1.4 million. At December 31, 2003, the fair value of the swap was approximately zero as the swap expired January 9, 2004. The balance in accumulated other comprehensive income was also approximately zero. Additionally, we have recognized in income a realized loss of $1.7 million and $1.2 million for the years ended December 31, 2003 and 2002, as interest expense.

 

NOTE 4—MAJOR CUSTOMERS

 

The percentage of our crude oil handling revenues from major customers were as follows:

 

     FOR THE YEARS ENDED
DECEMBER 31,


 
     2003

    2002

 
    

% OF TOTAL

REVENUES


   

% OF TOTAL

REVENUES


 

Chevron Texaco Corporation

   22 %   9 %

Marathon Oil Company(1)

   18 %   24 %

Shell Trading formerly Equiva Trading Company(1)

   13 %   9 %

British-Borneo USA, Inc.

   9 %   10 %

El Paso Production(1)

   3 %   10 %

(1) Represents affiliated companies.

 

NOTE 5—RELATED PARTY TRANSACTIONS

 

We derive a portion of our revenues from our members and their affiliated companies. We generated approximately $15.0 million, $25.6 million and $28.4 million in affiliated revenue. In addition, we paid Manta Ray Gathering Company, L.L.C., a subsidiary of GulfTerra Energy Partners, approximately $2.4 million in 2003 and $2.1 million in 2002 and 2001 for management, administrative and general overhead. During 2000, we were charged and paid Shell, the then operator, an additional management fee of approximately $1.7 million associated with the repair of our ruptured pipeline. Our other members disputed this additional charge and we were subsequently reimbursed $1.6 million in 2001.

 

NOTE 6—COMMITMENTS AND CONTINGENCIES

 

Legal

 

In the normal course of business, we are involved in various legal actions arising from our operations. In the opinion of management, the outcome of these legal actions will not have a significant adverse effect on our financial position or results of operations.

 

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Index to Financial Statements

POSEIDON OIL PIPELINE COMPANY, L.L.C.

 

NOTES TO FINANCIAL STATEMENTS—(Continued)

 

Environmental

 

We are subject to extensive federal, state, and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. We have no reserves for environmental matters, and during the next five years, we do not expect to make any significant capital expenditures relating to environmental matters.

 

It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. 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 increasingly strict environmental laws, regulations and 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. As this information becomes available, or other relevant developments occur, we will make accruals accordingly.

 

Other

 

We are subject to regulation under the Outer Continental Shelf Lands Act, which calls for nondiscriminatory transportation on pipelines operating in the outer continental shelf region of the Gulf of Mexico, and regulation under the Hazardous Liquid Pipeline Safety Act. Operations in offshore federal waters are regulated by the United States Department of the Interior.

 

In February 1998, we entered into an oil purchase and sale agreement with Pennzoil Exploration and Production (Pennzoil). The agreement provides that if Pennzoil delivers at least 7.5 million barrels by September 2003, we will refund $0.51 per barrel for all barrels delivered plus interest at 8 percent. At September 30, 2003, the barrels delivered were less than the 7.5 million barrels requirement and we believe that we have no obligation under this agreement. Also, in December 2001, we reversed our previous accrual for revenue refund of $1.7 million and recorded it as a component of crude oil handling revenue in our 2001 statement of income.

 

In January 2000, an anchor from a submersible drilling unit of Transocean 96 (Transocean) in tow ruptured our 24-inch crude oil pipeline north of the Ship Shoal 332 platform. The accident resulted in the release of approximately 2,200 barrels of crude oil in the waters surrounding our system, caused damage to the Ship Shoal 332 platform, and resulted in the shutdown of our system. Our cost to repair the damaged pipeline and clean up the crude oil released into the Gulf of Mexico was approximately $18 million and was charged to repair expenses in the year ended December 31, 2000. By the end of the first quarter 2000, our pipeline was repaired and placed back into service. In November 2002, we reached a settlement with multiple parties relating to this rupture and have recorded the proceeds of $26.6 million as other income in our 2002 statement of income.

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

 

     September 30,
2004 (1)


 
ASSETS         

Current Assets

        

Cash and cash equivalents

   $ 40,453  

Accounts receivable, net of allowance for doubtful accounts of $4.2 million at September 30, 2004

     156,997  

Affiliated note receivable

        

Other current assets

     32,055  
    


Total current assets

     229,505  

Property, Plant, and Equipment, net

     2,926,861  

Intangible Assets

     3,080  

Investments in Unconsolidated Affiliates

     210,742  

Other Assets

     26,101  
    


Total

   $ 3,396,289  
    


LIABILITIES AND PARTNERS’ EQUITY         

Current Liabilities

        

Current maturities of debt

   $ 5,000  

Accounts payable

     133,407  

Accrued interest

     26,361  

Other current liabilities

     35,045  
    


Total current liabilities

     199,813  

Long-Term Debt

     1,878,456  

Other Long-Term Liabilities

     42,384  

Commitments and Contingencies

        

Minority Interest

     (12 )

Partners’ Equity:

        

Common units (60,638,989 units outstanding at September 30, 2004)

     929,110  

Series C units (10,937,500 units outstanding at September 30, 2004)

     333,063  

General partner

     13,475  
    


Total Partners’ Equity

     1,275,648  
    


Total

   $ 3,396,289  
    



(1) The September 30, 2004 amounts do not reflect any pro forma impacts of the merger, repayments of debt, changes in ownership of our common unitholders or any other purchase accounting-related adjustments to be made by Enterprise in connection with the merger—see Note 2.

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P.

 

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per unit amounts)

 

    Six Months
Ended
June 30,


    Three Months
Ended
September 30,


    Nine Months
Total
September 30,


    Three Months
Ended


    Nine Months
Ended


 
           
    2004 (1)

    September 30, 2003

 

OPERATING REVENUES

  $ 445,557     $ 231,165     $ 676,722     $ 213,831     $ 680,957  
   


 


 


 


 


OPERATING EXPENSES

                                       

Cost of natural gas and other products

    124,522       61,651       186,173       64,277       240,415  

Operation and maintenance

    100,463       64,361       164,824       51,221       140,416  

Depreciation, depletion and amortization

    52,303       28,994       81,297       25,218       73,761  

Gain on sale of long-lived assets

    (24 )     (12 )     (36 )     (18,964 )     (18,707 )
   


 


 


 


 


Total operating expenses

    277,264       154,994       432,258       121,752       435,885  
   


 


 


 


 


OPERATING INCOME

    168,293       76,171       244,464       92,079       245,072  
   


 


 


 


 


EQUITY IN INCOME OF UNCONSOLIDATED AFFILIATES

    5,466       2,101       7,567       3,195       9,498  
   


 


 


 


 


Minority interest income (expense)

    12       1,813       1,825       (889 )     (969 )

Other income

    284       188       472       250       942  

Interest and debt expense

    54,727       27,951       82,678       33,197       99,521  

Loss due to early redemptions of debt

    16,285               16,285       1,225       4,987  
   


 


 


 


 


INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE

    103,043       52,322       155,365       60,213       150,035  

Cumulative effect of accounting change

                                    1,690  
   


 


 


 


 


NET INCOME

  $ 103,043     $ 52,322     $ 155,365     $ 60,213     $ 151,725  
   


 


 


 


 


ALLOCATION OF NET INCOME TO:

                                       

Series B unitholders

                          $ 4,018     $ 11,792  
                           


 


General partner:

                                       

Income before cumulative effect of accounting change

  $ 42,549     $ 21,550     $ 64,099     $ 18,031     $ 48,747  

Cumulative effect of accounting change

                                    17  
   


 


 


 


 


Total allocation to general partner

  $ 42,549     $ 21,550     $ 64,099     $ 18,031     $ 48,764  
   


 


 


 


 


Common unitholders:

                                       

Income before cumulative effect of accounting change

  $ 51,087     $ 26,044     $ 77,131     $ 31,337     $ 72,951  

Cumulative effect of accounting change

                                    1,340  
   


 


 


 


 


Total allocation to common unitholders

  $ 51,087     $ 26,044     $ 77,131     $ 31,337     $ 74,291  
   


 


 


 


 


Series C unitholders:

                                       

Income before cumulative effect of accounting change

  $ 9,407     $ 4,728     $ 14,135     $ 6,827     $ 16,545  

Cumulative effect of accounting change

                                    333  
   


 


 


 


 


Total allocation to Series C unitholders

  $ 9,407     $ 4,728     $ 14,135     $ 6,827     $ 16,878  
   


 


 


 


 


EARNINGS PER UNIT:

                                       

Basic income per unit before cumulative effect of accounting change

  $ 0.86     $ 0.43     $ 1.30     $ 0.63     $ 1.54  

Cumulative effect of accounting change, per unit (basic)

                                    0.03  
   


 


 


 


 


Basic net income per unit

  $ 0.86     $ 0.43     $ 1.30     $ 0.63     $ 1.57  
   


 


 


 


 


Diluted income per unit before cumulative effect of accounting change

  $ 0.86     $ 0.43     $ 1.30     $ 0.62     $ 1.53  

Cumulative effect of accounting change, per unit (diluted)

                                    0.03  
   


 


 


 


 


Diluted net income per unit

  $ 0.86     $ 0.43     $ 1.30     $ 0.62     $ 1.56  
   


 


 


 


 



(1) Amounts shown for the 2004 periods do not reflect any pro forma impacts of the merger, repayments of debt, changes in ownership of our common unitholders or any other purchase accounting-related adjustments to be made by Enterprise in connection with the merger—see Note 2.

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

 

   

Six Months
Ended

June 30,


    Three Months
Ended
September 30,


    Nine Months
Total
September 30,


   

Nine Months
Ended
September 30,

2003


 
    2004(1)

   

OPERATING ACTIVITIES

                               

Net income

  $ 103,043     $ 52,322     $ 155,365     $ 151,725  

Adjustments to reconcile net income to cash flows provided by operating activities:

                               

Cumulative effect of accounting change

                            (1,690 )

Depreciation, depletion and amortization in operating expenses

    52,303       28,994       81,297       73,761  

Amortization of debt issuance costs, premiums and discounts

    2,651       1,209       3,860       5,977  

Equity in income of unconsolidated affiliates

    (5,466 )     (2,101 )     (7,567 )     (9,498 )

Distributions received from unconsolidated affiliates

    1,450       750       2,200       11,390  

Gain on sale of long-lived assets

    (24 )     (12 )     (36 )     (18,707 )

Loss due to write-off of unamortized debt issuance costs

    3,884               3,884       4,987  

Other noncash items

    6,352       533       6,885       2,910  

Net effect of changes in operating accounts

    (27,961 )     4,186       (23,775 )     (11,500 )
   


 


 


 


Cash provided by operating activities

    136,232       85,881       222,113       209,355  
   


 


 


 


INVESTING ACTIVITIES

                               

Capital expenditures

    (86,107 )     (31,418 )     (117,525 )     (246,295 )

Proceeds from sale of assets

    197       278       475       77,448  

Investments in unconsolidated affiliates

    (17,947 )     (2,419 )     (20,366 )     (33,879 )

Proceeds from sale of equity investments

                            1,342  
   


 


 


 


Cash used in investing activities

    (103,857 )     (33,559 )     (137,416 )     (201,384 )
   


 


 


 


FINANCING ACTIVITIES

                               

Borrowings under debt agreements, net of debt issuance costs

    586,531       59,958       646,489       835,537  

Repayments of debt

    (522,585 )     (60,000 )     (582,585 )     (861,000 )

Distributions paid to partners

    (142,317 )     (72,067 )     (214,384 )     (167,974 )

Distributions paid to minority interests

                            (642 )

Contribution from general partner

    480       98       578       4  

Net proceeds from issuance of common units, Series F convertible units and conversion of Series F convertible units

    48,536       34,324       82,860       208,949  

Unit option buyout

            (7,627 )     (7,627 )        
   


 


 


 


Cash provided by (used in) financing activities

    (29,355 )     (45,314 )     (74,669 )     14,874  
   


 


 


 


NET CHANGE IN CASH AND CASH EQUIVALENTS

    3,020       7,008       10,028       22,845  

CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD

    30,425       33,445       30,425       36,099  
   


 


 


 


CASH AND CASH EQUIVALENTS, END OF PERIOD

  $ 33,445     $ 40,453     $ 40,453     $ 58,944  
   


 


 


 


Schedule of non-cash financing activities:

                               

Investment in Cameron Highway Oil Pipeline Company joint venture

                          $ 50,836  
                           


Redemption of Series B preference units contributed from our general partner

                          $ 1,986  
                           



(1) Amounts shown for the 2004 periods do not reflect any pro forma impacts of the merger, repayments of debt, changes in ownership of our common unitholders or any other purchase accounting-related adjustments to be made by Enterprise in connection with the merger—see Note 2.

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P.

 

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE LOSS

(Dollars in thousands)

 

Comprehensive Income

 

     Six Months
Ended
June 30,


    Three Months
Ended
September 30,


   Nine Months
Total
September 30,


   Three Months
Ended


   Nine Months
Ended


               
     2004(1)

   September 30, 2003

Net income

   $ 103,043     $ 52,322    $ 155,365    $ 60,213    $ 151,725

Other comprehensive income (loss)

     (2,172 )     7,923      5,751      8,094      2,651
    


 

  

  

  

Total comprehensive income

   $ 100,871     $ 60,245    $ 161,116    $ 68,307    $ 154,376
    


 

  

  

  

 

Accumulated Other Comprehensive Loss

 

     Six Months
June 30,


    Three Months
September 30,


   

Nine Months

Total


 
     2004(1)

   

Beginning balance

   $ (9,027 )   $ (11,199 )   $ (9,027 )

Unrealized mark-to-market losses on cash flow hedges arising during period

     (10,716 )     (225 )     (10,941 )

Reclassification adjustments for changes in initial value of derivative instruments to settlement date

     8,544       8,148       16,692  
    


 


 


Ending balance

   $ (11,199 )   $ (3,276 )   $ (3,276 )
    


 


 


Accumulated other comprehensive loss allocated to:

                        

Common units’ interest

   $ (9,305 )   $ (2,670 )   $ (2,670 )
    


 


 


Series C units’ interest

   $ (1,742 )   $ (533 )   $ (533 )
    


 


 


General partner’s interests

   $ (152 )   $ (73 )   $ (73 )
    


 


 



(1) Amounts shown for the 2004 periods do not reflect any pro forma impacts of the merger, repayments of debt, changes in ownership of our common unitholders or any other purchase accounting-related adjustments to be made by Enterprise in connection with the merger—see Note 2.

 

See Notes to Unaudited Condensed Consolidated Financial Statements.

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of presentation

 

We are a Delaware limited partnership established in 1993 for the purpose of providing midstream energy services, including gathering, transportation, fractionation, storage and other related activities, for producers of natural gas and oil, onshore and offshore in the Gulf of Mexico. Our general partner is GulfTerra Energy Company, L.L.C. (“GulfTerra GP”), a Delaware limited liability company—see Note 2. References to “us”, “we”, “our”, or “GulfTerra” are intended to mean the consolidated business and operations of GulfTerra Energy Partners, L.P. References to “El Paso” refer to El Paso Corporation, its subsidiaries and affiliates.

 

On September 30, 2004, we completed our merger with Enterprise Products Partners L.P. (“Enterprise”). For additional information regarding the merger, see Note 2. Unless otherwise disclosed, these unaudited condensed consolidated financial statements do not reflect any pro forma impacts of the merger, repayments of debt—see Note 4, changes in ownership of our common unitholders, purchase accounting-related adjustments or any other adjustments to be made by Enterprise in connection with the merger. Effective September 30, 2004, most of our then outstanding limited partner interests were converted to Enterprise limited partner interests pursuant to the merger. Those limited partner interests that were not converted into Enterprise limited partner interests were purchased by Enterprise from El Paso for cash immediately prior to the merger. As a result of the merger, we ceased as being a publicly-traded company subject to the filing requirements of the Securities and Exchange Commission (“SEC”).

 

In the opinion of GulfTerra, the accompanying unaudited condensed consolidated financial statements include all adjustments consisting of normal recurring accruals necessary for a fair presentation. Although we believe the disclosures in these financial statements are adequate to make the information presented not misleading, certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to the rules and regulations of the SEC.

 

The results of operations for the six months ended June 30, 2004, the three months ended September 30, 2004 or the total for the nine months ended September 30, 2004 are not necessarily indicative of the results to be expected for the full year.

 

Dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars, unless otherwise stated.

 

Certain reclassifications have been made to the prior year’s financial statements to conform to the current year presentation. Typhoon Oil Pipeline, a wholly-owned subsidiary, has transportation agreements with BHP Billiton and ChevronTexaco which provide that Typhoon Oil purchase the oil produced at the inlet of its pipeline for an index price less an amount that compensates Typhoon Oil for transportation services. At the outlet of its pipeline, Typhoon Oil resells this oil back to these producers at the same index price. As disclosed in our 2003 annual report on Form 10-K, as amended, we now record revenue from these buy/sell transactions upon delivery of the oil based on the net amount billed to the producers. For the three and nine months ended September 30, 2003, we reduced by $69.8 million and $191.7 million our revenues and cost of natural gas and other products to conform to the current period presentation. This revision had no effect on operating income, net income or partners’ equity.

 

With respect to our Texas intrastate pipeline system, which we acquired in April 2002, we had previously used the pre-acquisition accounting methodology for the cash settlement of natural gas imbalance receivables, which included the cash settlement amounts as a component of operating revenues and cost of natural gas and

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

other products. However, effective January 1, 2004, we have conformed our accounting for cash settlements on that system to the same method we use to account for imbalance receivable settlements on our other systems, which method accounts for these types of cash settlements as an adjustment to cost of natural gas and other products. We have determined that this revision is not material to our previously reported financial statements. Accordingly, we have not revised our previously filed financial statements to reflect this change in methodology.

 

Accounting for stock-based compensation

 

Under the terms of the merger agreement with Enterprise, we were obligated to repurchase, before the effective time of the merger, all outstanding employee and director unit options that had not been exercised or otherwise cancelled. As a result, we had no outstanding unit options at September 30, 2004. Historically, we used the intrinsic value method established in Accounting Principles Board Opinion (“APB”) No. 25, Accounting for Stock Issued to Employees , to value unit options issued to directors of our general partner. We used the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 123, Accounting for Stock-Based Compensation , to account for all of our other equity-based compensation programs. The costs associated with our unit options accounted for under APB No. 25 had no impact on net income for the six months ended June 30, 2004, the three months ended September 30, 2004 and the three and nine months ended September 30, 2003, as these options had an exercise price equal to the market value of the underlying common units on the date of grant. Historical compensation expense amounts associated with our unit options accounted for under SFAS No. 123 are shown in the following table.

 

If compensation expense had been determined by applying the fair value method in SFAS No. 123 to all of our grants, our net income allocated to common unitholders and net income per common unit would have approximated the pro forma amounts below (dollars in thousands, except per unit amounts). As a result of applying SFAS No. 123 to all unit options, there was no difference between our historical and pro forma earnings per unit amounts.

 

     Six Months
Ended
June 30,


    Three Months
Ended
September 30,


    Nine Months
Total
September 30,


    Three Months
Ended


    Nine Months
Ended


 
     2004

    September 30, 2003

 

Net income as reported

   $ 103,043     $ 52,322     $ 155,365     $ 60,213     $ 151,725  

Add: Equity-based compensation expense included in reported net income using SFAS No. 123

     267       142       409       404       1,083  

Less: Pro forma equity-based compensation expense determined using the fair value method as if all unit options were accounted for under SFAS No. 123

     (300 )     (142 )     (442 )     (406 )     (1,126 )
    


 


 


 


 


Pro forma net income

   $ 103,010     $ 52,322     $ 155,332     $ 60,211     $ 151,682  
    


 


 


 


 


Pro forma net income allocated to common unitholders

   $ 51,054     $ 26,044     $ 77,098     $ 31,335     $ 74,248  
    


 


 


 


 


Earnings per common unit:

                                        

Basic, as reported and pro forma

   $ 0.86     $ 0.43     $ 1.30     $ 0.63     $ 1.57  
    


 


 


 


 


Diluted, as reported and pro forma

   $ 0.86     $ 0.43     $ 1.30     $ 0.62     $ 1.56  
    


 


 


 


 


 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Inventory

 

In June 2004, we purchased pipeline inventory, consisting of parts and materials, from El Paso—see Note 8. This inventory is included on our unaudited condensed consolidated balance sheet as of September 30, 2004, in other current assets. We use the average cost method to account for our inventory and we value our inventory at the lower of its cost or market value.

 

Consolidation of variable interest entities

 

During the first quarter of 2004, we adopted the provisions of Financial Accounting Standards Board Interpretation (“FIN”) No. 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin (“ARB”) No. 51 , as replaced by FIN No. 46-R. This interpretation defines a variable interest entity as a legal entity whose equity owners do not have sufficient equity at risk and/or a controlling financial interest in the entity and excludes certain joint ventures of other entities that meet the characteristics of a business. Our adoption of FIN No. 46 had no effect on our reported results or financial position.

 

Two-class method of computing earnings per common unit

 

During the second quarter of 2004, we adopted the provisions of Emerging Issues Task Force (“EITF”) 03-6, Participating Securities and the Two-Class Method under SFAS No. 128 . EITF 03-6 requires the use of the two-class method of determining basic earnings per unit. Under the two-class method, distributions to equity owners are subtracted from earnings, and any remaining earnings would be allocated to the various classes of owners in proportion to their right to receive distributions as if those earnings had been distributed. The total of distributions to each class of owner plus the amount allocated to each class would be used to compute earnings per unit for that class. Because our distributions to owners exceeded earnings during the periods presented, as has historically been the case, the two-class method did not produce any change in result from the way we have traditionally computed earnings per unit. As a result, the adoption of this standard had no effect on our earnings per unit calculation for the six months ended June 30, 2004, the three months ended September 30, 2004 and the three and nine months ended September 30, 2003.

 

2. MERGER WITH ENTERPRISE AND RELATED TRANSACTIONS

 

General description of merger

 

On September 30, 2004, Enterprise and GulfTerra completed the merger of GulfTerra with a wholly-owned subsidiary of Enterprise, with GulfTerra being the surviving entity thereof (the “GulfTerra Merger”). Unless otherwise disclosed, these unaudited condensed consolidated financial statements do not reflect any pro forma impacts of the GulfTerra Merger, repayments of debt—see Note 4, changes in ownership of our common unitholders, purchase accounting-related adjustments or any other adjustments to be made by Enterprise in connection with the GulfTerra Merger.

 

The aggregate value of the total consideration Enterprise paid or issued to complete the GulfTerra Merger was approximately $3.8 billion. Pursuant to the merger agreements, the GulfTerra Merger occurred in several interrelated transactions as described below.

 

    Step One . On December 15, 2003, Enterprise purchased a 50% membership interest in our general partner, GulfTerra GP, from El Paso for $425 million in cash. As a result of Step One of the merger, GulfTerra GP was owned 50% by Enterprise and 50% by El Paso.

 

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NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

    Step Two . On September 30, 2004, the GulfTerra Merger was consummated and GulfTerra and GulfTerra GP became wholly-owned subsidiaries of Enterprise. Step Two of the merger included the following transactions:

 

    Immediately prior to closing the GulfTerra Merger, the general partner of Enterprise (“Enterprise GP”) acquired El Paso’s remaining 50% membership interest in GulfTerra GP for $370 million in cash paid to El Paso and the issuance of a 9.9% membership interest in Enterprise GP to El Paso. Subsequently, Enterprise GP contributed this 50% membership interest in GulfTerra GP to Enterprise.

 

    Immediately prior to closing the GulfTerra Merger, Enterprise paid $500 million in cash to El Paso for our 10,937,500 outstanding Series C units and 2,876,620 of our common units. After giving effect to this purchase, our remaining 57,762,369 common units were converted into 104,549,823 Enterprise common units using a conversion ratio of 1.81 Enterprise common units for each GulfTerra common unit outstanding.

 

Enterprise’s assumption of Series F2 convertible unit obligations

 

Upon completion of the GulfTerra Merger, Enterprise assumed our obligations associated with the outstanding Series F2 convertible units. As a result, the 80 Series F2 convertible units outstanding at the merger date were converted into rights to receive Enterprise common units. The number Enterprise common units and the price per unit were adjusted based on the 1.81 conversion ratio. For additional information regarding the Series F convertible units, see Note 6.

 

Repayment of certain GulfTerra debt in connection with the merger

 

In connection with the closing of our merger with Enterprise on September 30, 2004, we repaid, in full, the amounts outstanding under our revolving credit facility and senior secured term loans using funds contributed by Enterprise—see Note 4. The closing of our merger with Enterprise constituted a change of control, and thus a default, under our credit agreements. In order to avoid the default, Enterprise will contribute $961.7 million to us at closing on September 30, 2004, which we will use to fully repay our outstanding obligations and related interest of $1.2 million under these agreements. All such contributions and repayments are not reflected in our September 30, 2004 unaudited condensed consolidated financial statements. For additional information regarding our remaining debt obligations, see Note 4.

 

Tender offers for GulfTerra notes in connection with the merger

 

On August 4, 2004, in anticipation of completing the merger, Enterprise commenced four cash tender offers to purchase any and all of our outstanding senior and senior subordinated notes having a total outstanding principal amount of approximately $921.5 million. In connection with the tender offers, we executed supplements to the indentures governing these notes that eliminated certain restrictive covenants and default provisions contained in those indentures.

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Substantially all of our notes ($915 million of $921.5 million) were tendered pursuant to the tender offers. On October 5, 2004, Enterprise purchased the notes for a total price of approximately $1.1 billion, which included $27 million related to consent payments. The following table shows our four senior debt obligations affected, including the principal amount of each series of notes tendered, as well as the payment made by Enterprise to complete the tender offers.

 

Description


   Principal
Amount
Tendered


   Cash payments made by Enterprise

      Accrued
Interest


  

Tender

Price (1)


  

Total

Price


8.50% Senior Subordinated Notes due 2010
(Represents 98.2% of principal amount outstanding)

   $ 212,057    $ 6,209    $ 246,366    $ 252,575

10.625% Senior Subordinated Notes due 2012
(Represents 99.9% of principal amount outstanding)

     133,916      4,901      167,612      172,513

8.50% Senior Subordinated Notes due 2011
(Represents 99.5% of principal amount outstanding)

     319,823      9,364      359,379      368,743

6.25% Senior Notes due 2010
(Represents 99.7% of principal amount outstanding)

     249,250      5,366      274,073      279,439
    

  

  

  

Totals

   $ 915,046    $ 25,840    $ 1,047,430    $ 1,073,270
    

  

  

  


(1) Tender price includes consent payment of $30 per $1,000 principal amount tendered.

 

For additional information regarding our senior and senior subordinated notes, see Note 4.

 

Other merger-related transactions

 

Prior to our merger with Enterprise, we determined that it was in our and our unitholders’ best interest to offer selected employees of El Paso incentives to continue to focus on the business of the partnership during the merger process. We accounted for the cost of these incentives under the provisions of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities . In March 2004, we recorded a liability and a related deferred charge of $4.3 million, which was reflected in other current liabilities and other current assets on our balance sheets. Our liability was estimated based upon the number of employees accepting the offer and the discounted amount they were expected to be paid. During the six months ended June 30, 2004 and the three months ended September 30, 2004, we recorded $2.8 million and $1.5 million of amortization expense associated with these incentives.

 

Additionally, pursuant to the terms of the engagement letter, we agreed to pay UBS Securities (“UBS”) $10.3 million for advisory fees related to our merger with Enterprise. In the first quarter of 2004, we paid UBS $3.5 million upon receiving a fairness opinion related to the merger, and the remaining $6.8 million was paid on September 30, 2004.

 

Furthermore, during the three months ended September 30, 2004, we recognized a merger-related expense of $4.9 million associated with our repurchase of the outstanding unit options prior to closing the merger with Enterprise. Under the merger agreement with Enterprise, we were obligated to repurchase, at reasonable prices and before the effective time of the merger, all outstanding employee and director unit options that had not been exercised or otherwise cancelled. Approximately 1,000,000 common unit options were outstanding at the merger date, which we repurchased for approximately $13 million. For the unit options accounted for under the provisions of SFAS No. 123, the purchase price recorded had two components. The purchase price paid up to the fair value of the options as of the valuation date was recorded as the repurchase of an equity instrument. The payment above that fair value amount was recorded as compensation expense. For our unit options accounted for

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

under APB No. 25, the amount paid up to the intrinsic value of the options repurchased was also accounted for as the repurchase of an equity instrument, with any amount paid in excess of the intrinsic value recorded as compensation expense.

 

Lastly, during the six months ended June 30, 2004 and the three months ended September 30, 2004, we recognized additional merger-related expenses primarily for legal and audit fees totaling $1.5 million and $1.1 million. All of our merger-related costs are included in operation and maintenance expenses on our unaudited condensed consolidated statements of income and are allocated across all of our operating segments.

 

3. PROPERTY, PLANT AND EQUIPMENT

 

Our property, plant and equipment consisted of the following at the dates indicated:

 

     September 30,
2004


Property, plant and equipment, at cost

      

Pipelines

   $ 2,880,523

Platforms and facilities

     165,179

Processing plants

     317,638

Oil and natural gas properties

     131,166

Storage facilities

     337,023

Construction-in-progress

     45,005
    

       3,876,534

Less accumulated depreciation, depletion and amortization

     949,673
    

Total property, plant and equipment, net

   $ 2,926,861
    

 

The values shown in the table above do not reflect any purchase accounting-related adjustments recorded by Enterprise as a result of the GulfTerra Merger—see Note 2.

 

4. DEBT OBLIGATIONS

 

Prior to the September 30, 2004 debt repayments and subsequent tender offer payments, both in connection with the merger—see Note 2, our debt consisted of the following at the dates indicated:

 

    

September 30,

2004


 

Borrowings under:

        

Revolving Credit Facility (1)

   $ 462,000  

Senior Secured Term Loans (1)

     498,500  

Senior Notes, 6.25% fixed-rate, due June 2010 (2)

     250,000  

Senior Subordinated Notes, 10.375% fixed-rate, due June 2009 (3)

        

Senior Subordinated Notes, 8.50% fixed-rate, due June 2010 (2,4)

     215,915  

Senior Subordinated Notes, 8.50% fixed-rate, due June 2011 (2)

     321,600  

Senior Subordinated Notes, 10.625% fixed-rate, due Dec. 2012 (2)

     134,000  
    


Total principal amount

     1,882,015  

Other, including unamortized premiums and discounts

     1,441  
    


Subtotal long-term debt

     1,883,456  

Less current maturities of debt

     (5,000 )
    


Long-term debt

   $ 1,878,456  
    


 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 


(1) In connection with closing the merger, Enterprise contributed approximately $962 million to us on September 30, 2004 to repay in full the $960.5 million in principal amount due under these debt agreements, plus $1.2 million of related accrued interest—see Note 2.
(2) On October 5, 2004, $915 million of these senior note obligations were tendered to Enterprise pursuant to its tender offers made in connection with the merger—see Note 2.
(3) In June 2004, we redeemed, at a premium, all of our 10.375% Senior Subordinated Notes due 2009.
(4) In April 2004, we redeemed, at a premium, approximately $39.1 million of our 8.5% Senior Subordinated Notes due June 2010.

 

After giving effect to the September 30, 2004 debt repayments and subsequent tender offer payments, both in connection with the merger—see Note 2, our debt consisted of the following at the dates indicated:

 

    

October 5,

2004


  

September 30,

2004


 

Borrowings under:

               

Revolving Credit Facility

          $ 462,000  

Senior Secured Term Loans

            498,500  

Senior Notes, 6.25% fixed-rate, due June 2010

   $ 750      250,000  

Senior Subordinated Notes, 10.375% fixed-rate, due June 2009

               

Senior Subordinated Notes, 8.50% fixed-rate, due June 2010

     3,858      215,915  

Senior Subordinated Notes, 8.50% fixed-rate, due June 2011

     1,777      321,600  

Senior Subordinated Notes, 10.625% fixed-rate, due Dec. 2012

     84      134,000  
    

  


       6,469      1,882,015  

Other, including unamortized premiums and discounts

            1,441  
    

  


       6,469      1,883,456  

Less current maturities of debt

            (5,000 )
    

  


     $ 6,469    $ 1,878,456  
    

  


 

Parent-Subsidiary guarantor relationships

 

After giving effect to the completion of Enterprise’s tender offers on October 5, 2004—see Note 2, we have $6.5 million in senior and senior subordinated notes outstanding. These obligations are jointly, severally, fully and unconditionally guaranteed by us and each of our subsidiaries, excluding our unrestricted subsidiaries.

 

Debt maturities

 

After giving effect to the completion of Enterprise’s tender offers on October 5, 2004—see Note 2, aggregate maturities of the principal amounts of long-term debt are none for the remainder of 2004 and in each of the years 2005 through 2008 and $6.5 million in total after 2008.

 

Information regarding variable interest rates paid

 

On September 30, 2004, and prior to the merger-related repayment, we had $462 million outstanding under our revolving credit facility at an average interest rate of 3.82%. On September 30, 2004, and prior to the merger-related repayment, we had $498.5 million outstanding under our senior secured term loans at an average interest rate of 4.07%.

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Loss due to early redemptions of debt

 

We recognized losses associated with early redemptions of debt as follows:

 

     Six Months
Ended
June 30,


   Three Months
Ended
September 30,


   Nine Months
Total
September 30,


   Three Months
Ended


   Nine Months
Ended


     2004

   September 30, 2003

Loss due to payment of redemption premiums

   $ 12,401         $ 12,401              

Loss due to write-off of unamortized debt issuance costs

     3,884           3,884    $ 1,225    $ 4,987
    

  
  

  

  

     $ 16,285         $ 16,285    $ 1,225    $ 4,987
    

  
  

  

  

 

Joint venture debt obligations

 

We have ownership interests in three joint ventures having long-term debt obligations: Cameron Highway Oil Pipeline Company (“Cameron Highway”); Deepwater Gateway, L.L.C. (“Deepwater Gateway”); and Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”). The following table shows (i) our ownership interest in each entity at September 30, 2004, (ii) total long-term debt obligations (including current maturities) of each unconsolidated affiliate on that date (on a 100% basis to the joint venture), and (iii) the estimated corresponding scheduled maturities of such long-term debt.

 

   

Our

Ownership
Interest


   

Total


  Scheduled Maturities of Long-Term Debt

        2004

  2005

  2006

  2007

  2008

 

After

2008


Cameron Highway (1)

  50.0 %   $ 297,000               $ 16,250   $ 32,500   $ 156,250   $ 92,000

Deepwater Gateway

  50.0 %     149,500   $ 5,500   $ 22,000     22,000     22,000     22,000     56,000

Poseidon (2)

  36.0 %     116,000                             116,000      
         

 

 

 

 

 

 

Total

        $ 562,500   $ 5,500   $ 22,000   $ 38,250   $ 54,500   $ 294,250   $ 148,000
         

 

 

 

 

 

 


(1) Cameron Highway has a total borrowing capacity under its project loan facility of $325 million. The scheduled maturities for Cameron Highway assume that the construction loan is or will be converted into a term loan on June 30, 2005 and the scheduled repayments will begin on September 30, 2006.
(2) Poseidon has a total borrowing capacity of $170 million under its revolving credit facility.

 

At September 30, 2004, long-term debt for Cameron Highway consisted of $197 million outstanding under a variable-rate construction loan and $100 million of senior secured notes. Cameron Highway has a borrowing capacity of $225 million under its construction loan. At September 30, 2004, the average variable interest rate charged under Cameron Highway’s construction loan agreement was 4.97%. The interest rate on Cameron Highway’s senior secured notes is 3.25% over the rate on 10-year U.S. treasury securities, which at September 30, 2004 was 7.4%.

 

At September 30, 2004, long-term debt for Deepwater Gateway consisted of $149.5 million due under a project finance loan used to fund a portion of the construction costs of the Marco Polo tension leg platform (“TLP”) and related facilities. Construction of the Marco Polo TLP was completed during the first quarter of 2004, and in June 2004, Deepwater Gateway converted the project finance loan into a term loan which matures in June 2009. At September 30, 2004, the average variable interest rate charged under Deepwater Gateway’s term loan was 3.6%.

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

At September 30, 2004, long-term debt for Poseidon consisted of $116 million due under a revolving credit facility, which matures in January 2008. At September 30, 2004, the average variable interest rate charged under Poseidon’s credit agreement was 3.7%.

 

5. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

 

We own interests in various related businesses that are accounted for using the equity method. In general, we use the equity method of accounting for an investment in which we own 20% to 50% of its outstanding ownership interests and exercise significant influence over its operating and financial policies. Our investments in unconsolidated affiliates totaled $210.7 million at September 30, 2004.

 

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

 

    

Six Months
Ended

June 30,


   

Three Months
Ended

September 30,


   

Nine Months
Total

September 30,


   

Three Months
Ended


  

Nine Months
Ended


             
     2004

    September 30, 2003

Cameron Highway (1)

   $ (57 )           $ (57 )             

Coyote

     1,118     $ 577       1,695     $ 516    $ 1,771

Deepwater Gateway (2)

     1,209       3,111       4,320               

Poseidon

     3,226       2,127       5,353       1,797      6,845

Other (3)

     (30 )     (3,714 )     (3,744 )     882      882
    


 


 


 

  

Total

   $ 5,466     $ 2,101     $ 7,567     $ 3,195    $ 9,498
    


 


 


 

  


(1) Cameron Highway is a development stage company at September 30, 2004; therefore, there are no operating revenues or expenses. Since its formation in June 2003, it has incurred organizational expenses and received interest income. In September 2004, construction of the Cameron Highway oil pipeline system was completed and we anticipate that operations will begin during the fourth quarter of 2004 or the first quarter of 2005.
(2) The Marco Polo TLP, which is owned by Deepwater Gateway, was installed in the first quarter of 2004. First production and thus volumetric payments started in July 2004. In April 2004, Deepwater Gateway began receiving monthly demand payments of $2.1 million. Prior to the installation of this platform, Deepwater Gateway was a development stage company; therefore, there were no operating revenues or operating expenses.
(3) The 2004 period includes a $3.7 million loss associated with our write-off of a note receivable from El Paso we received in connection with the sale of our interest in Copper Eagle Gas Storage, L.L.C. (“Copper Eagle”) to El Paso in August 2003. The 2003 period includes a $0.9 million gain we initially recorded on the sale of our interest in Cooper Eagle to El Paso. See Note 8 for additional information regarding this related party transaction.

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table presents unaudited summarized income statement information for our current unconsolidated affiliates from which we have recorded equity earnings (for the periods indicated, on a 100% basis).

 

    

Six Months Ended

June 30, 2004


   

Three Months Ended

September 30, 2004


 
     Revenues

   Net
Income (Loss)


    Revenues

   Net
Income (Loss)


 

Cameron Highway

          $ (298 )          $ (290 )

Deepwater Gateway

   $ 6,300      2,800     $ 9,598      6,124  

Poseidon

     18,116      8,780       9,399      6,193  

Coyote

     3,600      2,244       1,800      1,137  
     Nine Months Total
September 30, 2004


            
     Revenues

  

Net

Income (Loss)


            

Cameron Highway

          $ (588 )               

Deepwater Gateway

   $ 15,898      8,924                 

Poseidon

     27,515      14,973                 

Coyote

     5,400      3,381                 
     Three Months Ended
September 30, 2003


    Nine Months Ended
September 30, 2003


 
     Revenues

  

Net

Income


    Revenues

  

Net

Income


 

Cameron Highway

                              

Deepwater Gateway

          $ 14            $ 32  

Poseidon

   $ 9,425      5,278     $ 32,632      19,356  

Coyote

     1,800      1,014       5,625      3,524  

 

6. PARTNERS’ CAPITAL

 

On September 30, 2004, we completed our merger with Enterprise—see Note 2. These unaudited condensed consolidated financial statements do not reflect any changes in ownership of our common unitholders as a result of the merger. Effective September 30, 2004, most of our then outstanding limited partner interests were converted to Enterprise limited partner interests pursuant to the merger. Those limited partner interests that were not converted into Enterprise limited partner interests were purchased by Enterprise from El Paso for cash immediately prior to the merger. As a result of the merger, we ceased as being a publicly-traded company subject to the filing requirements of the SEC.

 

During the first nine months of 2004 we received net proceeds of approximately $78.3 million from the conversion of 80 Series F1 convertible units into 2,061,109 common units (45 Series F1 convertible units were converted into 1,146,418 common units with proceeds paid to us of $45 million during the first six months of 2004). As a result of these conversions in 2004, all of the Series F1 convertible units were converted into GulfTerra common units by the holder prior to our merger with Enterprise. On the merger closing date, Enterprise assumed our obligations associated with the outstanding Series F2 convertible units.

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table reflects our cash distribution history for the nine months ended September 30, 2004 (dollars in millions, except per unit amounts):

 

Month Paid


   Common
Unit


   Common
Unitholders


   Series C
Unitholders


   General
Partner


February

   $ 0.71    $ 41.5    $ 7.8    $ 21.3

May

   $ 0.71    $ 42.4    $ 7.8    $ 21.7

August

   $ 0.71    $ 42.6    $ 7.8    $ 21.7

 

7. EARNINGS PER COMMON UNIT

 

The following table sets forth the computation of basic and diluted earnings per common unit (dollars in thousands, except per unit amounts):

 

    Six Months
Ended
June 30,


  Three Months
Ended
September 30,


  Nine Months
Total
September 30,


  Three Months
Ended


  Nine Months
Ended


           
    2004

  September 30, 2003

Numerator:

                             

Numerator for basic earnings per common unit:

                             

Income before cumulative effect of accounting change

  $ 51,087   $ 26,044   $ 77,131   $ 31,337   $ 72,951

Cumulative effect of accounting change

                            1,340
   

 

 

 

 

    $ 51,087   $ 26,044   $ 77,131   $ 31,337   $ 74,291
   

 

 

 

 

Denominator:

                             

Denominator for basic earnings per common unit:

                             

weighted-average common units

    59,298     59,946     59,515     50,072     47,388

Effect of dilutive securities:

                             

Unit options

    244                 270     139

Restricted units

    23     26     26     14     11

Series F convertible units

    1           1     29     115
   

 

 

 

 

Denominator for diluted earnings per common unit:

                             

adjusted for weighted-average common units

    59,566     59,972     59,542     50,385     47,653
   

 

 

 

 

Basic earnings per common unit

                             

Income before cumulative effect of accounting change

  $ 0.86   $ 0.43   $ 1.30   $ 0.63   $ 1.54

Cumulative effect of accounting change

                            0.03
   

 

 

 

 

    $ 0.86   $ 0.43   $ 1.30   $ 0.63   $ 1.57
   

 

 

 

 

Diluted earnings per common unit

                             

Income before cumulative effect of accounting change

  $ 0.86   $ 0.43   $ 1.30   $ 0.62   $ 1.53

Cumulative effect of accounting change

                            0.03
   

 

 

 

 

    $ 0.86   $ 0.43   $ 1.30   $ 0.62   $ 1.56
   

 

 

 

 

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

8. RELATED PARTY TRANSACTIONS

 

For the nine months ended September 30, 2004, there were no changes to our related party relationships. Prior to our merger with Enterprise, our largest related party was our parent company, El Paso. As a result of our merger with Enterprise, El Paso is no longer classified as a related party to us.

 

Revenues received from related parties for the six months ended June 30, 2004 and the three months ended September 30, 2004, were approximately 17 percent and 16 percent of our total revenue. Revenues received from related parties for the three and nine months ended September 30, 2003, were approximately 12 percent and 13 percent of our total revenue.

 

Our transactions with related parties and affiliates are as follows:

 

     Six Months
Ended
June 30,


   Three Months
Ended
September 30,


   Nine Months
Total
September 30,


   Three Months
Ended


   Nine Months
Ended


     2004

   September 30, 2003

Revenues received from related parties:

                                  

Natural gas pipelines and plants

   $ 43,513    $ 21,107    $ 64,620    $ 18,054    $ 67,068

Oil and NGL logistics

     30,247      15,250      45,497      6,842      22,686
    

  

  

  

  

Total

   $ 73,760    $ 36,357    $ 110,117    $ 24,896    $ 89,754
    

  

  

  

  

Expenses paid to related parties:

                                  

Cost of natural gas and other products

   $ 16,011    $ 4,046    $ 20,057    $ 6,191    $ 26,988

Operation and maintenance

     45,665      23,501      69,166      22,229      68,039
    

  

  

  

  

Total

   $ 61,676    $ 27,547    $ 89,223    $ 28,420    $ 95,027
    

  

  

  

  

Reimbursements received from related parties:

                                  

Operation and maintenance

   $ 1,629    $ 707    $ 2,336    $ 659    $ 1,860
    

  

  

  

  

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

The following table provides summary data categorized by our related parties:

 

     Six Months
Ended
June 30,


   Three Months
Ended
September 30,


   Nine Months
Total
September 30,


   Three Months
Ended


   Nine Months
Ended


     2004

   September 30, 2003

Revenues received from related parties:

                                  

El Paso

   $ 73,146    $ 35,977    $ 109,123    $ 24,986    $ 89,754

Enterprise

     614      380      994              
    

  

  

  

  

Total

   $ 73,760    $ 36,357    $ 110,117    $ 24,986    $ 89,754
    

  

  

  

  

Cost of natural gas and other products paid to related parties:

                                  

El Paso

   $ 16,011    $ 4,046    $ 20,057    $ 6,191    $ 26,988
    

  

  

  

  

Operation and maintenance expenses paid to related parties:

                                  

El Paso

   $ 45,443    $ 23,389    $ 68,832    $ 22,120    $ 67,723

Unconsolidated affiliates

     222      112      334      109      316
    

  

  

  

  

Total

   $ 45,665    $ 23,501    $ 69,166    $ 22,229    $ 68,039
    

  

  

  

  

Reimbursements received from related parties:

                                  

Unconsolidated affiliates

   $ 1,629    $ 707    $ 2,336    $ 659    $ 1,860
    

  

  

  

  

 

Our accounts receivable due from related parties consisted of the following as of:

 

    

September 30,

2004


El Paso

   $ 18,512

Enterprise

     279

Unconsolidated affiliates

     8,496
    

Total

   $ 27,287
    

 

Our accounts payable due to related parties consisted of the following as of:

 

    

September 30,

2004


El Paso

   $ 35,167

Unconsolidated Subsidiaries

     3,830
    

Total

   $ 38,997
    

 

Other matters

 

Petal . In September 2003, we entered into a nonbinding letter of intent with El Paso, regarding the proposed development and sale of a natural gas storage cavern, and the proposed sale of an undivided interest in a related pipeline and other facilities related to that natural gas storage cavern. In June 2004, we and El Paso terminated the letter of intent and we announced that we would hold a nonbinding open season to determine market interest for up to 5.0 Bcf of firm natural gas storage capacity, and up to 500,000 MMBtu/d of firm transportation on the Petal pipeline, all available in the third quarter of 2007.

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

Copper Eagle . In August 2003, a majority-owned subsidiary of ours sold its interest in Copper Eagle Gas Storage, L.L.C. (“Copper Eagle”) to El Paso. Copper Eagle is developing a natural gas storage project located outside of Phoenix, Arizona. Under the original sale agreement with El Paso, we had the right to receive $6.2 million of the sale proceeds, including a note receivable for $4.9 million that was to be paid quarterly beginning in January 2004 and ending in October 2004. As of September 30, 2004, we had received principal payments totaling $1.3 million from El Paso related to the note receivable. Prior to the sale, we accounted for our investment in Copper Eagle using the equity method.

 

The proposed natural gas storage project has received strong local opposition by developers and residents due to the close proximity to residential communities. Further, the storage facilities will be near the Luke Air Force Base and the Arizona legislature recently reached a resolution which prohibits the development of a hydrocarbon storage facility within a nine mile range of an air force base or airport. As a result of these developments, we have changed our view on the probability that the Copper Eagle natural gas storage project will actually be developed and we wrote-off the remaining $3.7 million note receivable from El Paso as uncollectible during the third quarter of 2004. The write-off was recorded as a reduction to equity in income of unconsolidated affiliates—see Note 5. In addition, we reduced our minority interest balance by $1.8 million and recognized minority interest income of $1.8 million, which reflects the portion of the write-off allocated to the minority interest owner of our subsidiary.

 

Indemnifications . In addition to the related party transactions discussed above, pursuant to the terms of many of the purchase and sale agreements we have entered into with various entities controlled directly or indirectly by El Paso, we have been indemnified for potential future liabilities, expenses and capital requirements above a negotiated threshold. Some of our agreements obligate certain indirect subsidiaries of El Paso to pay for capital costs related to maintaining assets which were acquired by us, if such costs exceed negotiated thresholds. We have not made any claims during the nine months ended September 30, 2004 or 2003. However, for the full year of 2003, we made claims for approximately $5 million of costs incurred during the year ended December 31, 2003, as costs exceeded the established thresholds for 2003.

 

Wilson storage operating lease commitment . In connection with our April 2002 purchase of the EPN Holding assets from El Paso, we obtained a long-term operating lease commitment related to the Wilson natural gas storage facility, which is operated by one of our direct subsidiaries. From the acquisition date until the second quarter of 2004, El Paso guaranteed our direct subsidiary’s payment and performance under this commitment. In the second quarter of 2004, El Paso was released from the guarantee and, thus, we now are solely liable for our direct subsidiary’s payment and performance under this operating lease agreement.

 

9. COMMITMENTS AND CONTINGENCIES

 

Litigation

 

We are sometimes named as a defendant in litigation relating to our normal business operations. Although we insure against various business risks, to the extent management believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from legal proceedings as a result of ordinary business activity. Management is not aware of any significant litigation, pending or threatened, that would have a significant adverse effect on our financial position or results of operations.

 

Environmental

 

Environmental costs for remediation are accrued at their undiscounted estimated amounts based on known remediation requirements. Such accruals are based on management’s best estimate of the ultimate costs to

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

remediate a given site and take into account the likely effects of inflation and other societal and economic factors, including estimated associated legal costs. We expense amounts for clean up of existing environmental contamination caused by past operations which do not benefit future periods. We expense or capitalize expenditures for ongoing compliance with environmental regulations that relate to past or current operations as appropriate. As of September 30, 2004, we had an environmental liability initially estimated at $21 million, which is included in other long-term liabilities on our unaudited condensed consolidated balance sheet, for remediation costs expected to be incurred over time associated with mercury gas meters.

 

While the outcome of our outstanding environmental matters cannot be predicted with certainty, based on the information known to date and our existing accruals, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, results of operations or cash flows. It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws and regulations and claims for damage to property, employees, other persons and the environment resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties relating to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our current reserves are adequate.

 

Joint ventures

 

We conduct a portion of our activities through joint venture business arrangements formed to construct, operate and finance the development of our onshore and offshore midstream energy businesses. We are obligated to make our proportionate share of additional capital contributions to our joint ventures only to the extent that they are unable to satisfy their obligations from other sources including proceeds from credit arrangements. Examples of this type of business arrangement include our equity method investments in Cameron Highway, Deepwater Gateway and Poseidon.

 

Other commitments

 

Long-term debt-related commitments . We have long-term payment obligations under our senior and senior subordinated notes. See Note 4 for a description of these debt obligations.

 

Operating lease commitments . We lease certain storage facilities located in Texas (one natural gas facility and two NGL facilities). At September 30, 2004, the future minimum lease payments associated with these operating lease commitments are as follows: $0.4 million, 2004; $7 million, 2005; $7 million, 2006; $5.8 million, 2007; $3.2 million, 2008; and $1.8 million thereafter.

 

10. ACCOUNTING FOR HEDGING ACTIVITIES

 

A majority of our commodity purchases and sales, which relate to sales of oil and natural gas associated with our production operations, purchases and sales of natural gas associated with pipeline operations, sales of natural gas liquids (“NGL”) and purchases or sales of gas associated with our processing plants and our gathering activities, are at spot market or forward market prices. We use futures, forward contracts, and swaps to limit our exposure to fluctuations in the commodity markets and allow for a fixed cash flow stream from these activities.

 

In February and August 2003, we entered into derivative financial instruments to hedge our exposure during 2004 to changes in natural gas prices relating to gathering activities in the San Juan Basin. In September 2004, we settled the open San Juan natural gas hedges for October, November and December 2004, prior to their

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

expiration date and prior to our merger with Enterprise. The derivatives were financial swaps on 30,000 MMBtu per day whereby we received an average fixed price of $4.23 per MMBtu and paid a floating price based on the San Juan index. As a result of our early settlement of the open San Juan natural gas hedges, we paid the counterparties, J. Aaron and Company and UBS Energy LLC, $2.5 million during the third quarter of 2004. The derivatives were marked to fair value just prior to settlement and the loss on the settlement was recorded in accumulated other comprehensive income and will be reclassified to earnings in the periods that the previously hedged transaction would have occurred.

 

In September 2004 and prior to our merger with Enterprise, we entered into a derivative financial instrument to hedge our exposure during November 2004 through March 2005 to changes in natural gas prices relating to gathering activities in the San Juan Basin. The derivative is a financial swap on 40,000 MMBtu per day whereby we receive a fixed price of $6.71 per MMBtu and pay a floating price based on the San Juan index. As of September 30, 2004, the fair value of this cash flow hedge was a liability of $0.7 million, as the market price at this date was higher than the hedge price. As a result of our merger with Enterprise on September 30, 2004, Enterprise assumed the liability associated with the hedge. We are accounting for this derivative as a cash flow hedge under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities . No ineffectiveness exists in this hedging relationship because all purchase and sales prices are based on the same index and volumes as the hedge transaction. The counterparty for the San Juan hedge activity is UBS Energy LLC. We do not require collateral or anticipate non-performance by this counterparty.

 

During 2003, we entered into derivative financial instruments to hedge a portion of our business’ exposure to changes in NGL prices during 2004. We entered into financial swaps for 6,000 barrels per day for the period from August 2003 to September 2004. The average fixed price received was $0.47 per gallon for 2004 while we paid a monthly average floating price based on the Oil Pricing Information Service average price for each month. In September 2004, these cash flow hedges expired and for the six months ended June 30, 2004 and the three months ended September 30, 2004, we reclassified approximately $4.6 million and $5.2 million of unrealized losses from accumulated other comprehensive income to earnings. These reclassifications are included in our natural gas pipelines and plants segment. No ineffectiveness exists in this hedging relationship because all purchase and sales prices are based on the same index and volumes as the hedge transaction.

 

In connection with our GulfTerra Intrastate Alabama operations, we had fixed price contracts with specific customers for the sale of predetermined volumes of natural gas for delivery over established periods of time. We entered into cash flow hedges in 2003 to offset the risk of increasing natural gas prices. For January and February 2004, we contracted to purchase 20,000 MMBtu and for March 2004, we contracted to purchase 15,000 MMBtu. The average fixed price paid during 2004 was $5.28 per MMBtu while we received a floating price based on the Southern Natural Pipeline index as published by the periodical “Inside FERC”. In March 2004, these cash flow hedges expired and we reclassified a gain of approximately $45 thousand from accumulated other comprehensive income to earnings. This reclassification is included in our natural gas pipelines and plants segment. No ineffectiveness existed in this hedging relationship because all purchase and sale prices were based on the same index and volumes as the hedge transaction.

 

In July 2003, to achieve a more balanced mix of fixed rate debt and variable rate debt, we entered into an eight-year interest rate swap agreement to provide for a floating interest rate on $250 million of our 8  1 / 2 % senior subordinated notes due 2011. With this swap agreement, we paid the counterparty a LIBOR based interest rate plus a spread of 4.20% and received a fixed rate of 8  1 / 2 %. We accounted for this derivative as a fair value hedge under SFAS No. 133. In March 2004, we terminated our fixed to floating interest rate swap with our counterparty. The value of the transaction at termination was zero and as such neither we, nor our counterparty, were required to make any payments. Also, neither we, nor our counterparty, have any future obligations under this transaction.

 

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Index to Financial Statements

GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

We estimate the entire $3.3 million of unrealized losses included in accumulated other comprehensive income at September 30, 2004, will be reclassified from accumulated other comprehensive income as a reduction to earnings over the next six months. When our derivative financial instruments are settled, the related amount in accumulated other comprehensive income is recorded in the income statement in operating revenues, cost of natural gas and other products, or interest and debt expense, depending on the item being hedged. The effect of reclassifying these amounts to the income statement line items is recording our earnings for the period related to the hedged items at the “hedged price” under the derivative financial instruments.

 

11. BUSINESS SEGMENT INFORMATION

 

Historically, we have segregated our business activities into four distinct operating segments: Natural gas pipelines and plants; Oil and NGL logistics; Natural gas storage; and Platform services. Each of our segments are business units that offer different services and products that are managed separately since each segment’s operations required different technology and marketing strategies.

 

Prior our merger with Enterprise, we used performance cash flows to (i) evaluate the performance of our business segments, (ii) determine how resources would be allocated among the segments and (iii) develop strategic plans for our overall business. We defined performance cash flows as earnings before interest, depreciation and amortization and other adjustments. Historically, our lenders and equity investors viewed our performance cash flows measure as an indication of our ability to generate sufficient cash to meet debt obligations or to pay distributions to partners. In addition, this non-GAAP measure was useful to investors because it allowed them to evaluate the effectiveness of our business segments from an operational perspective, exclusive of the costs to finance those activities and depreciation and amortization (neither of which are directly relevant to the efficiency of those operations). Performance cash flows may not be comparable to measurements used by other companies and should not be used a substitute for net income or other performance measures. In this context and for transition purposes only, we have presented performance cash flows as our measure of segment earnings for the six months ended June 30, 2004, the three months ended September 30, 2004 and the three and nine months ended September 30, 2003. Beginning October 1, 2004, we will conform our non-GAAP financial measures to those used by Enterprise.

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

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

 

    Natural Gas
Pipelines &
Plants


  Oil and
NGL
Logistics


  Natural
Gas
Storage


    Platform
Services


  Non-Segment
Activity (1)


    Total

Six Months Ended June 30, 2004

                                       

Revenue from external customers

  $ 364,493   $ 35,005   $ 24,193     $ 12,932   $ 8,934     $ 445,557

Intersegment revenue

    64                   1,164     (1,228 )      

Equity in income of unconsolidated affiliates

    1,118     3,169     (30 )     1,209             5,466

Performance cash flows

    165,917     20,720     16,782       12,179              

Assets

    2,344,760     464,228     317,221       175,161     84,721       3,386,091

Three Months Ended September 30, 2004

                                       

Revenue from external customers

  $ 188,567   $ 20,871   $ 11,129     $ 6,772   $ 3,826     $ 231,165

Intersegment revenue

    26                   566     (592 )      

Equity in income of unconsolidated affiliates

    576     2,126     (3,713 )     3,112             2,101

Performance cash flows

    79,655     13,021     5,806       5,471              

Assets

    2,360,943     471,399     301,894       176,734     85,319       3,396,289

Nine Months Total September 30, 2004

                                       

Revenue from external customers

  $ 553,060   $ 55,876   $ 35,322     $ 19,704   $ 12,760     $ 676,722

Intersegment revenue

    90                   1,730     (1,820 )      

Equity in income of unconsolidated affiliates

    1,694     5,295     (3,743 )     4,321             7,567

Performance cash flows

    245,572     33,741     22,588       17,650              

Assets

    2,360,943     471,399     301,894       176,734     85,319       3,396,289

Three Months Ended September 30, 2003

                                       

Revenue from external customers (2)

  $ 180,879   $ 13,205   $ 10,252     $ 5,185   $ 4,310     $ 213,831

Intersegment revenue

    29                   600     (629 )      

Equity in income of unconsolidated affiliates

    516     1,797     882                     3,195

Performance cash flows

    80,002     26,782     7,518       4,885              

Assets

    2,227,900     444,253     314,192       163,000     132,424       3,281,769

Nine Months Ended September 30, 2003

                                       

Revenue from external customers (2)

  $ 577,585   $ 41,182   $ 32,729     $ 15,668   $ 13,793     $ 680,957

Intersegment revenue

    97           278       2,004     (2,379 )      

Equity in income of unconsolidated affiliates

    1,771     6,845     882                     9,498

Performance cash flows

    236,223     51,279     22,587       15,397              

Assets

    2,227,900     444,253     314,192       163,000     132,424       3,281,769

(1) Represents predominantly our oil and natural gas production activities as well as intersegment eliminations. Our intersegment revenues, along with our intersegment operating expenses, consist of normal course of business-type transactions between our operating segments. We record an intersegment revenue elimination, which is the only elimination included in the “Non-Segment Activity” column, to remove intersegment transactions.
(2) Revenue from external customers for our Oil and NGL Logistics segment has been reduced by $69.8 million and $191.7 million for the quarter and nine months ended September 30, 2003 to reflect the revision of Typhoon Oil Pipeline’s revenues and cost of natural gas and other products to conform to the current period presentation—see Note 1.

 

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GULFTERRA ENERGY PARTNERS, L.P.

 

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

 

A reconciliation of our segment performance cash flows to our consolidated net income is as follows:

 

     Six Months
Ended
June 30,


    Three Months
Ended
September 30,


    Nine Months
Total
September 30,


    Three Months
Ended


   Nine Months
Ended


             
     2004

    September 30, 2003

Natural gas pipelines and plants

   $ 165,917     $ 79,655     $ 245,572     $ 80,002    $ 236,223

Oil and NGL logistics

     20,720       13,021       33,741       26,782      51,279

Natural gas storage

     16,782       5,806       22,588       7,518      22,587

Platform services

     12,179       5,471       17,650       4,885      15,397
    


 


 


 

  

Segment performance cash flows

     215,598       103,953       319,551       119,187      325,486

Plus: Other, non-segment results

     8,692       2,150       10,842       3,640      11,917

 Equity in income of unconsolidated affiliates

     5,466       2,101       7,567       3,195      9,498

 Cumulative effect of accounting change

                                    1,690

Less: Interest and debt expense

     54,727       27,951       82,678       33,197      99,521

 Loss due to early redemptions of debt

     16,285               16,285       1,225      4,987

 Depreciation, depletion and amortization

     52,303       28,994       81,297       25,218      73,761

 Distributions received from unconsolidated affiliates

     1,450       750       2,200       3,160      11,390

 Minority interest

     (12 )     (1,813 )     (1,825 )     889      969

 Net cash payment received from El Paso

     1,960               1,960       2,120      6,238
    


 


 


 

  

Net income

   $ 103,043     $ 52,322     $ 155,365     $ 60,213    $ 151,725
    


 


 


 

  

 

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Index to Financial Statements

Report of Independent Registered Public Accounting Firm

 

To the Owners of El Paso Hydrocarbons, L.P.

and El Paso NGL Marketing Company, L.P.:

 

In our opinion, the accompanying combined balance sheets and the related combined statements of operations, comprehensive income and changes in accumulated comprehensive income (loss), owners’ net investment and cash flows present fairly, in all material respects, the financial position of El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. (collectively, the “Companies”) at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Companies’ management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

As discussed in Note 5 to the combined financial statements, the Companies have significant transactions and relationships with affiliated entities. Because of these relationships, it is possible that the terms of these transactions are not the same as those that would have resulted from transactions with wholly unrelated entities.

 

/s/    PricewaterhouseCoopers LLP

 

Houston, Texas

April 15, 2004

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

COMBINED BALANCE SHEETS

(In thousands)

 

     December 31,

     2003

    2002

ASSETS               

Current assets

              

Accounts receivable

              

Trade, net

   $ 160,475     $ 94,360

Affiliates

     16,632       59,132

Natural gas imbalance receivable from affiliate

     3,022       3,472

Inventory

     14,964       10,702

Other current assets

     4,148       1,662
    


 

Total current assets

     199,241       169,328

Property, plant and equipment, net

     316,255       325,808
    


 

Total assets

   $ 515,496     $ 495,136
    


 

LIABILITIES AND OWNERS’ NET INVESTMENT               

Current liabilities

              

Accounts payable

              

Trade

   $ 128,638     $ 109,707

Affiliates

     48,442       55,945

NGL and NGL product liabilities

     14,213       8,998

Other current liabilities

     2,623       1,025
    


 

Total current liabilities

     193,916       175,675

Environmental liabilities

     2,190       2,288
    


 

Total liabilities

     196,106       177,963
    


 

Commitments and contingencies

              

Accumulated other comprehensive income (loss)

     (32 )     50

Owners’ net investment

     319,422       317,123
    


 

Total owners’ net investment

     319,390       317,173
    


 

Total liabilities and owners’ net investment

   $ 515,496     $ 495,136
    


 

 

See accompanying notes.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

COMBINED STATEMENTS OF OPERATIONS

(In thousands)

 

     For the Year Ended December 31,

     2003

   2002

   2001

Operating revenues

                    

Sales of NGL and NGL products

                    

Third parties

   $ 1,068,121    $ 799,300    $ 511,357

Affiliates

     15,842      238,815      118,221

Processing and other services

                    

Third parties

     48,410      27,477      5,776

Affiliates

     298,327      484,527      242,883
    

  

  

       1,430,700      1,550,119      878,237
    

  

  

Operating expenses

                    

Cost of natural gas and other products

                    

Third parties

     845,785      907,319      647,255

Affiliates

     540,850      570,915      173,857

Operations and maintenance

                    

Third parties

     14,876      15,314      17,818

Affiliates

     7,250      9,554      8,206

Depreciation and amortization

     12,138      11,921      12,396

Taxes other than income

     2,321      2,374      2,570
    

  

  

       1,423,220      1,517,397      862,102
    

  

  

Operating income

     7,480      32,722      16,135

Other income

     —        32      —  

Other expense

     —        5      —  

Interest income

     99      —        2,396
    

  

  

Net income

   $ 7,579    $ 32,749    $ 18,531
    

  

  

 

See accompanying notes.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

COMBINED STATEMENTS OF CASH FLOWS

(In thousands)

 

     For the Year Ended December 31,

 
     2003

    2002

    2001

 

Cash flows from operating activities

                        

Net income

   $ 7,579     $ 32,749     $ 18,531  

Adjustments to reconcile net income to cash provided by operating activities

                        

Depreciation and amortization

     12,138       11,921       12,396  

Working capital changes net of noncash transactions:

                        

Accounts receivable

     (23,615 )     (4,194 )     (71,629 )

Natural gas imbalance receivable from affiliate

     450       12,854       (16,326 )

Inventory

     (4,388 )     (1,077 )     1,156  

Other current assets

     (2,536 )     (1,612 )     —    

Accounts payable

     11,428       (51,395 )     159,605  

NGL and NGL product liabilities

     5,215       7,730       1,268  

Other current liabilities

     1,692       369       (40 )

Non-working capital changes:

                        

Decrease in environmental liabilities

     (98 )     (86 )     (12 )
    


 


 


Net cash provided by operating activities

     7,865       7,259       104,949  
    


 


 


Cash flows from investing activities

                        

Capital expenditures

     (2,585 )     (3,551 )     (2,242 )

Proceeds from asset sale

     —         —         133,000  
    


 


 


Net cash provided by (used in) investing activities

     (2,585 )     (3,551 )     130,758  
    


 


 


Cash flows from financing activities

                        

Net cash distributions to owners

     (5,280 )     (3,708 )     (235,707 )
    


 


 


Net cash used in financing activities

     (5,280 )     (3,708 )     (235,707 )
    


 


 


Net change in cash and cash equivalents

     —         —         —    

Cash and cash equivalents

                        

Beginning of period

     —         —         —    
    


 


 


End of period

   $ —       $ —       $ —    
    


 


 


 

See accompanying notes.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

COMBINED STATEMENTS OF OWNERS’ NET INVESTMENT

(In thousands)

 

     For the Year Ended December 31,

 
     2003

    2002

    2001

 

Owners’ net investment

                        

Balance at beginning of period

   $ 317,123     $ 288,082     $ 505,258  

Net income

     7,579       32,749       18,531  

Net cash distributions to owners

     (5,280 )     (3,708 )     (235,707 )
    


 


 


Balance at end of period

     319,422       317,123       288,082  

Accumulated other comprehensive income (loss)

                        

Balance at beginning of period

     50       (496 )     —    

Other comprehensive income (loss)

     (82 )     546       (496 )
    


 


 


Balance at end of period

     (32 )     50       (496 )
    


 


 


Total owners’ net investment

   $ 319,390     $ 317,173     $ 287,586  
    


 


 


 

See accompanying notes.

 

F-247


Table of Contents
Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

COMBINED STATEMENTS OF COMPREHENSIVE INCOME

AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)

(In thousands)

 

Comprehensive income

 

     Year Ended December 31,

 
     2003

    2002

   2001

 

Net income

   $ 7,579     $ 32,749    $ 18,531  

Other comprehensive income (loss)

     (82 )     546      (496 )
    


 

  


Total comprehensive income

   $ 7,497     $ 33,295    $ 18,035  
    


 

  


 

Accumulated Other Comprehensive Income (Loss)

 

     Year Ended December 31,

 
     2003

    2002

    2001

 

Beginning balance

   $ 50     $ (496 )   $ —    

Unrealized mark-to-market gains (losses) on cash flow hedges arising during the period

     2,657       2,152       (5,817 )

Reclassification adjustments for changes in initial value of derivative instruments to settlement date

     (2,739 )     (1,606 )     5,321  
    


 


 


Ending balance

   $ (32 )   $ 50     $ (496 )
    


 


 


 

See accompanying notes.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS

 

Note 1—Organization and Nature of Business

 

Organization

 

El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. are Delaware limited partnerships, whose limited and general partnership interests are owned by subsidiaries of El Paso Corporation. We own and operate assets located in south Texas, including nine cryogenic processing plants and related equipment with total processing capacity of 1,890 million cubic feet per day (MMcf/d), one natural gas treating plant with capacity of 150 MMcf/d, a 294-mile natural gas gathering system and a 3.8-mile natural gas liquids (NGL) pipeline. We gather natural gas, extract NGL from natural gas, process mixed NGL into component products (e.g., ethane, propane, butane, natural gasoline, and other products), and transport and market NGL and NGL products.

 

The terms “we,” “our” or “us” refer to El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. on a combined basis.

 

Sale to Enterprise Products Partners, L.P.

 

In December 2003, certain subsidiaries of El Paso Corporation entered into an agreement to sell us to Enterprise Products Operating, L.P. (Enterprise) for approximately $150 million, which sale is expected to close concurrent with the closing of the merger of a subsidiary of Enterprise Products Partners, L.P. with GulfTerra Energy Partners, L.P. (GulfTerra), both of which are master limited partnerships. Until the closing of the sale or termination of the agreement, we may not, without Enterprise’s consent engage in any action outside the ordinary course of business. As a result, our ability to incur liens, amend or terminate material agreements, issue equity, incur debt, sell assets, initiate or settle litigation, or change our accounting principles is limited. The parties’ obligations under the agreement to sell us are subject to the satisfaction of specified conditions including, among other things, obtaining Hart-Scott-Rodino and other third-party approvals and consents and consummating the merger.

 

Note 2—Significant Accounting Policies

 

Basis of Presentation

 

The accompanying combined financial statements have been prepared from El Paso Corporation’s historical accounting records of the combined companies and are presented on a carve-out basis to include the historical operations applicable to El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. In this context, no direct owner relationship existed among these entities. Accordingly, the net investment in these entities (owners’ net investment) is shown in lieu of owners’ equity in the combined financial statements. During 2001 and 2002, our owners contributed additional businesses to us in the form of entire legal entities and assets. The contribution of these additional businesses, which were under the common control of El Paso Corporation for all periods presented, constitutes a change in our reporting entity. Accordingly, our financial statements include the accounts and results of operations of these businesses for all periods presented on an “as-if pooled” basis. The net assets contributed have been initially recorded at the historical cost of El Paso Corporation.

 

Our combined financial statements are prepared on the accrual basis of accounting in conformity with accounting principles generally accepted in the United States of America. All significant intercompany accounts and transactions within the companies have been eliminated.

 

Throughout the periods covered by the combined financial statements, El Paso Corporation and its subsidiaries have provided cash management services to us through a centralized treasury system. As a result, all of our charges and cost allocations covered by the centralized treasury system were deemed to have been paid by

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

 

us to El Paso Corporation and its subsidiaries, in cash, during the period in which the cost was recorded in the combined financial statements. In addition, all of our cash receipts were advanced to El Paso Corporation and its subsidiaries as they were received. As a result of using these centralized treasury systems, the excess of cash receipts advanced over the charges and cash allocation is reflected as net cash contributions from/distributions to our owners in the combined statements of owners’ net investment and cash flows.

 

We have been allocated general and administrative expenses incurred by our owners in order to present our financial statements on a stand-alone basis. See Note 5 for a discussion of the amounts and method of allocation. All of the allocations in the combined financial statements are based on assumptions that management believes are reasonable under the circumstances. However, these allocations are not necessarily indicative of the costs and expenses that would have resulted had we operated as a separate entity.

 

Use of Estimates

 

The preparation of these combined financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures in these combined financial statements. While we believe these estimates are appropriate, actual results can, and often do, differ from those estimates.

 

Allowance for Doubtful Accounts

 

We have established an allowance for losses on accounts that we believe are uncollectible. We regularly review the collectibility of our accounts and adjust the allowance as necessary, primarily under the specific identification method. At December 31, 2003 and 2002, the allowance was approximately $892,000 and $582,000.

 

Natural Gas Imbalance

 

The natural gas imbalance results from differences in gas volumes we purchased and sold or consumed in our processing activities compared with the amounts we nominated for delivery. This imbalance is settled in kind through a tracking mechanism or a negotiated cash-out between parties and is valued at prices representing the estimated value of these imbalances upon settlement. Changes in natural gas prices will affect our valuation. We do not value our imbalances based on current month-end spot prices because it is not likely that we would purchase or receive natural gas at that point in time to settle the imbalance. Natural gas imbalances are reflected in imbalance receivable or imbalance payable, as appropriate, in our combined financial statements.

 

Inventory

 

Our inventory consists of NGL and NGL products and is carried at the lower of its cost or market with cost determined using the average cost method. We had no lower of cost or market adjustments in 2003 or 2002. In 2001, we recorded an adjustment of approximately $1.3 million to reduce the book value of our inventory to market.

 

Property, Plant and Equipment

 

Our processing and treating plants, as well as our natural gas gathering and NGL pipelines are recorded at historical cost. Provision for depreciation of property, plant and equipment is made on a straight-line basis over the estimated useful lives of these facilities using periods ranging from 30 to 40 years. Retirements, sales and

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

 

disposals of assets are recorded by eliminating the related cost and accumulated depreciation of the disposed assets with any resulting gains or losses reflected in income. Repairs and maintenance costs are expensed as incurred, while additions, improvements and replacements are capitalized.

 

Accounting for Asset Retirement Obligations

 

In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations. This statement requires companies to record a liability for the estimated retirement and removal of assets used in their business. The liability is recorded at its fair value, with a corresponding asset which is depreciated over the remaining useful life of the long-lived asset to which the liability relates.

 

On January 1, 2003, we adopted the provisions of SFAS No. 143. Our assets subject to asset retirement obligations include two of our processing plants, our natural gas gathering system and a portion of our NGL pipeline. We have identified these assets as having an indeterminate life in accordance with SFAS No. 143, which means that we cannot reasonably estimate the fair value of the retirement obligations. Accordingly, we did not recognize any asset or related liability for the cost of retiring or removing long-lived assets used in our business upon our adoption of SFAS No. 143. A liability for these asset retirement obligations will be recorded if and when the fair value obligation becomes measurable. Our estimate of the potential costs that would be required to settle these obligations if they were settled in the near term range from $6.2 million to $10.6 million.

 

Impairment and Disposal of Long-Lived Assets

 

We apply the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, to account for impairment and disposal of long-lived assets. Accordingly, we evaluate the recoverability of selected long-lived assets when adverse events or changes in circumstances indicate that the carrying value of an asset or group of assets may not be recoverable. We determine the recoverability of an asset or group of assets by estimating the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets at the lowest level for which separate cash flows can be measured. If the total of the undiscounted cash flows is less than the carrying amount for the assets, we estimate the fair value of the asset or group of assets and recognize the amount by which the carrying value exceeds the fair value, less cost to sell, as an impairment loss in income from operations in the period the impairment is determined.

 

Additionally, as required by SFAS No. 144, we classify long-lived assets to be disposed of other than by sale (e.g., abandonment, exchange or distribution) as held and used until the item is abandoned, exchanged or distributed. We evaluate assets to be disposed of other than by sale for impairment and recognize a loss for the excess of the carrying value over the fair value. Long-lived assets to be disposed of through sale recognition meeting specific criteria are classified as “Held for Sale” and measured at the lower of their cost or fair value less cost to sell. We report the results of operations of a component classified as held for sale, including any gain or loss in the period(s) in which they occur. We classify gains and losses resulting from sales of long-lived assets in operating income in accordance with the provisions of SFAS No. 144. We also reclassify the asset or assets as either held for sale or discontinued operations, depending on whether they have independently determinable cash flow and whether we have any continuing involvement.

 

NGL and NGL Product Liabilities

 

We record NGL and NGL product liabilities when we deliver more NGL and NGL products to customers than is available in our inventory. To accomplish these deliveries, we borrow the inventory of third parties in our possession and then must settle the liability by restoring the inventory. We value the liability at the appropriate index price based on location and the type of product borrowed.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

 

Fair Value of Financial Instruments

 

As of December 31, 2003 and 2002 our carrying amounts of accounts receivable and accounts payable approximate fair value due to the short-term nature of these instruments.

 

Revenue Recognition

 

Revenue from processing services is recognized in the period the natural gas is processed for the customer. Our processing contracts generally provide that we are compensated for our services from the retention of NGL extracted, fee-based terms and the sale of natural gas purchased for and not consumed in our processing activities. Revenues from NGL sales contracts, including the sale of NGL retained from processing, are recognized as sales of NGL and NGL products in our combined statements of operations and recorded upon the delivery of the NGL products specified in each individual contract. Pricing terms in these sales contracts are based upon market-related prices for such products and can include pricing differentials due to factors such as differing delivery locations and markets.

 

Cost of Natural Gas and Other Products

 

In providing our processing services, we incur and are responsible for costs based on the type of processing contracts. These costs include producer payments based on contracts which require us to pay the producer an amount for liquids extracted at a stated contract price, natural gas replacement costs, liquid fractionation costs and natural gas purchase costs.

 

Accounting for Price Risk Management Activities

 

Our business activities expose us to a variety of risks including commodity price risk. From time to time we engage in price risk management activities for non-trading purposes to manage market risks associated with the commodities we purchase and sell. Our price risk management activities involve the use of a variety of derivative financial instruments, including

 

    exchange-traded future contracts that involve cash settlement;

 

    forward contracts that involve cash settlements or physical delivery of a commodity; and

 

    swap contracts that require payments to (or receipts from) counterparties based on the difference between a fixed and a variable price, or two variable prices, for a commodity.

 

We account for all of our derivative instruments in accordance with the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. We record all derivatives in our balance sheets at their fair value as other assets or other liabilities and classify them as current or noncurrent based upon their anticipated settlement date.

 

For those instruments entered into to hedge risk and which qualify as hedges, we apply the provisions of SFAS No. 133, and the accounting treatment depends on our intended use for each instrument and its designation. In addition to its designation, a hedge must be effective. To be effective, changes in the value of the derivative or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged.

 

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies for undertaking various hedge transactions. All hedging instruments are

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

 

linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows or fair values of the hedged items. We discontinue hedge accounting prospectively if we determine that a derivative is not highly effective as a hedge or if we decide to discontinue the hedging relationship.

 

We had no open derivative contracts at January 1, 2001. During 2003, 2002 and 2001, we entered into both cash flow and fair value hedges that qualify for hedge accounting under SFAS No. 133 treatment. Changes in the fair value of a derivative designated as a cash flow hedge are recorded in accumulated other comprehensive income for the portion of the change in value of the derivative that is effective. The ineffective portion of the derivative is recorded in earnings in the current period. Classification in the income statement of the ineffective portion is based on the income classification of the item being hedged. At the date of the hedged transaction, we reclassify the gains or losses resulting from the sale, maturity, extinguishment or termination of derivative instruments designated as hedges from accumulated other comprehensive income to operating income in our combined statements of operations. For fair value hedges, changes in the fair value of the derivative and changes in the fair value of the related asset or liability associated with the hedged risk are recorded in our current period earnings, generally as a component of operating revenues in the case of a sale, or as a component of the cost of natural gas and other products in the case of a purchase. We classify cash inflows and outflows associated with the settlement of our derivative transactions as cash flows from operating activities in our combined statements of cash flows.

 

We may also purchase and sell instruments to economically hedge price fluctuations in the commodity markets. These instruments are not documented as hedges due to their short-term nature, or do not qualify under the provisions of SFAS No. 133 for hedge accounting due to the terms in the instruments. Where such derivatives do not qualify, or are not documented as a hedge, changes in their fair value are recorded in earnings in the current period.

 

During the normal course of our business, we may enter into contracts that qualify as derivatives under the provisions of SFAS No. 133. As a result, we evaluate our contracts to determine whether derivative accounting is appropriate. Contracts that meet the criteria of a derivative and qualify as “normal purchase” and “normal sales,” as those terms are defined in SFAS No. 133, may be excluded from SFAS No. 133.

 

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This statement amends SFAS No. 133 to incorporate several interpretations of the Derivatives Implementation Group (DIG), and also makes several minor modifications to the definition of a derivative as it was defined in SFAS No. 133. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. Our combined financial statements were not initially affected by adopting this standard, although the FASB and DIG continue to deliberate on the application of the standard to certain derivative contracts, which may affect our combined financial statements in the future.

 

Environmental Costs and Other Contingent Liabilities

 

We expense or capitalize expenditures for ongoing compliance with environmental regulations that relate to past or current operations as appropriate. We expense amounts for clean up of existing environmental contamination caused by past operations that do not significantly increase the value of the property or extend its useful life. We record liabilities when our environmental assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

 

of inflation and other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency or other organizations. These estimates are subject to revision in future periods based on actual costs or new circumstances and are included in our combined balance sheets at their undiscounted amounts. We currently have a reserve for environmental matters.

 

We are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we will establish the necessary accruals. As of December 31, 2003 and 2002, we did not have any reserves for pending or threatened legal matters.

 

Income Taxes

 

We are organized as limited partnerships and are therefore, not subject to taxation for federal or state income tax purposes. The taxable income or loss resulting from our operations will ultimately be included in the federal and state income tax returns of our owners. Accordingly, no provision for income taxes has been recorded in the accompanying combined financial statements.

 

Comprehensive Income

 

Our comprehensive income is determined based on net income, adjusted for changes in accumulated other comprehensive income (loss) from our cash flow hedging activities.

 

Recent Pronouncements

 

Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity

 

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement provides guidance on the classification of financial instruments as equity, liabilities, or as both liabilities and equity. The provisions of SFAS No. 150 are effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning July 1, 2003. We adopted the provisions of SFAS No. 150 on July 1, 2003, and our adoption did not have a material effect on our combined financial statements.

 

Consolidation of Variable Interest Entities

 

In January 2003, the FASB issued FIN No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 . This interpretation defines a variable interest entity (VIE) as a legal entity whose equity owners do not have sufficient equity at risk and/or a controlling financial interest in the entity. This standard requires that a company consolidate a VIE if it is allocated a majority of the VIEs losses and/or returns, including fees paid by the entity. In December 2003, the FASB issued FIN 46-R, which amended FIN No. 46, to extend its effective date until the first quarter of 2004 for all types of entities except special purpose entities (SPEs). In addition, FIN No. 46-R also limited the scope of FIN No. 46 to exclude certain joint ventures of other entities that meet the characteristics of businesses.

 

We have no VIEs as defined by FIN Nos. 46 and 46-R and do not expect our adoption of this statement to have a significant effect on our reported results or financial position.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

 

Note 3—Transportation and Fractionation Asset Sale

 

In February 2001, we sold three fractionation plants and related facilities for $133 million to GulfTerra. These assets had been acquired by El Paso Corporation in a purchase business combination in December 2000 and contributed to us at their fair values. We did not realize any gain or loss on the disposal of these assets.

 

We deposited the proceeds from the sale in a qualified intermediary account. As El Paso Corporation found qualifying acquisitions during 2001, we distributed amounts out of the qualified intermediary account to El Paso Corporation. We distributed the remaining balance in September 2001. While the proceeds were in the qualified intermediary account, we earned interest of approximately $2.4 million on the funds. This amount is reported as interest income in our statement of operations for the year ended December 31, 2001.

 

Note 4—Property, Plant and Equipment

 

Our property, plant and equipment consist of the following at December 31 (in thousands):

 

     2003

    2002

 

Property, plant and equipment at cost

                

Processing plants, pipelines and related facilities

   $ 354,815     $ 352,750  

Construction work-in-progress

     1,596       1,076  
    


 


       356,411       353,826  

Less accumulated depreciation, depletion and amortization

     (40,156 )     (28,018 )
    


 


Total property, plant and equipment, net

   $ 316,255     $ 325,808  
    


 


 

Note 5—Related Party Transactions

 

We enter into various types of transactions with affiliates in the normal course of business on market-related terms and conditions including processing of natural gas for, selling natural gas and NGL products to and purchasing natural gas and NGL products from affiliates. In addition, our owners allocate to us general and administrative costs incurred on our behalf. Our allocation is based on an average rate representing our gross property, plant and equipment; earnings before interest and taxes; and direct labor costs, each expressed as a percentage of the total amount recorded by El Paso Corporation. We were allocated general and administrative costs of approximately $5.8 million, $7.9 million and $6.4 million in 2003, 2002 and 2001, which are included in operations and maintenance expense in our statements of operations.

 

Substantially all of the individuals who perform the day-to-day financial, administrative, accounting and operational functions for us, as well as those who are responsible for directing and controlling us, are currently employed by El Paso Corporation. Eligible employees participate in benefit plans provided by El Paso Corporation which include a defined benefit pension plan, a defined contribution plan covering substantially all domestic employees and health care benefit plans. Costs associated with these plans are proportionately allocated to us. For the years ended December 31, 2003, 2002 and 2001, these allocated costs were approximately $1.4 million, $1.7 million and $1.8 million and are included in operations and maintenance expense in our statements of operations.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

 

The following table provides summary data of our transactions with related parties for the years ended December 31 (in thousands):

 

     2003

   2002

   2001

Revenues received from related parties:

                    

Sales of NGL and NGL products

   $ 15,842    $ 238,815    $ 118,221

Processing and other services

     298,327      484,527      242,883
    

  

  

     $ 314,169    $ 723,342    $ 361,104
    

  

  

Expenses paid to related parties:

                    

Cost of natural gas and other products

   $ 540,850    $ 570,915    $ 173,857

Operations and maintenance

     7,250      9,554      8,206
    

  

  

     $ 548,100    $ 580,469    $ 182,063
    

  

  

 

For the years ended December 31, 2003, 2002 and 2001, revenues received from related parties comprised approximately 22.0 percent, 46.7 percent and 41.1 percent of our operating revenues. During 2003, we reduced our transactions with El Paso Merchant Energy North America Company and began to replace those transactions with similar arrangements with third parties.

 

The following table provides summary data categorized by our related parties for the years ended December 31 (in thousands):

 

     2003

   2002

   2001

Revenues received from related parties:

                    

El Paso Corporation

                    

El Paso Merchant Energy North America Company

   $ 235,520    $ 645,243    $ 335,459

El Paso Field Services

     66,697      71,046      10,390

El Paso Production Company

     8,748      5,152      8,915

GulfTerra Energy Partners, L.P.

     3,204      1,901      6,340
    

  

  

     $ 314,169    $ 723,342    $ 361,104
    

  

  

Purchased NGL and NGL product costs paid to related parties:

                    

El Paso Corporation

                    

El Paso Field Services

   $ 338,272    $ 426,378    $ 87,780

El Paso Production Company

     64,282      31,268      11,337

Colorado Interstate Gas Company

     24,087      15,599      13,907

El Paso Merchant Energy North America Company

     68,432      30,774      39,190

GulfTerra Energy Partners, L.P.

     45,777      66,896      21,643
    

  

  

     $ 540,850    $ 570,915    $ 173,857
    

  

  

Operating expenses paid to related parties:

                    

El Paso Field Services

   $ 7,250    $ 9,554    $ 8,206
    

  

  

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

 

Our accounts receivable due from and accounts payable due to related parties consisted of the following at December 31 (in thousands):

 

     2003

   2002

Accounts receivable

             

El Paso Corporation

             

El Paso Field Services

   $ 14,595    $ 6,831

El Paso Merchant Energy North America Company

     425      51,015

El Paso Production Company

     736      1,014

GulfTerra Energy Partners, L.P.

     876      272
    

  

     $ 16,632    $ 59,132
    

  

Natural gas imbalance receivable

             

GulfTerra Energy Partners, L.P.

   $ 3,022    $ 3,472
    

  

Accounts payable

             

El Paso Corporation

             

El Paso Field Services

   $ 33,719    $ 37,556

El Paso Production Company

     9,281      6,099

Colorado Interstate Gas Company

     1,603      1,584

El Paso Merchant Energy North America Company

     87      1,875

GulfTerra Energy Partners, L.P.

     3,752      8,831
    

  

     $ 48,442    $ 55,945
    

  

 

Note 6—Accounting for Hedging Activities

 

A majority of our commodity purchases and sales, which relate to sales of NGL and NGL products associated with our processing and marketing activities, are at spot market or forward market prices. We use futures, forward contracts and swaps to limit our exposure to fluctuations in the commodity markets and allow for a fixed cash flow stream from our natural gas and NGL processing and marketing activities and to limit our exposure to commodity price fluctuations in our inventory of NGL and NGL products. On January 1, 2001, we adopted the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. We did not have any derivative contracts in place at December 31, 2000, and therefore, we did not recognize any transition adjustment in our combined financial statements.

 

In connection with some our processing activities, we are compensated by sharing in the value of the NGLs that are extracted as part of the processing activities. We entered into fixed for floating cash flow hedge transactions to provide stable cash flows from the anticipated sales for some of these NGL and NGL products. Additionally, we enter into fixed for floating fair value hedge transactions to protect the value of a portion of our NGL and NGL products in our existing inventory. We generally enter into hedge transactions for periods not exceeding 18 months and no ineffectiveness exists in our hedging relationships because all purchase and sale prices are based on the same index and volumes as the hedge transactions.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

 

The following table presents information about our hedging activities at December 31:

 

     2003

    2002

    2001

 

Cash Flow Hedges

                        

Commodity Price Swaps

                        

Number of open contracts

     5       6       32  

Contract expiration

     1 month       1-3 months       1-6 months  

Contract volumes (Mbbls)

     46       11       50  

Weighted average price received (per bbl)

   $ 25.49     $ 21.88     $ 13.65  

Weighted average price paid (per bbl)

   $ 26.18     $ 17.16     $ 23.61  

Swap fair value asset (liability) (in thousands)

   $ (32 )   $ 50     $ (496 )
     2003

    2002

    2001

 

Fair Value Hedges

                        

Commodity Price Swaps

                        

Number of open contracts

     2       3       1  

Contract expiration

     1 month       1 month       1 month  

Contract volumes (Mbbls)

     20       50       10  

Weighted average price received (per bbl)

   $ 23.73     $ 18.55     $ 20.16  

Weighted average price paid (per bbl)

   $ 28.04     $ 22.79     $ 13.65  

Swap fair value asset (liability) (in thousands)

   $ (86 )   $ (212 )   $ 65  

bbl = barrel
Mbbl = thousands of barrels

 

We estimate the entire $32,000 of unrealized losses included in other comprehensive income at December 31, 2003, will be reclassified from accumulated other comprehensive income as a reduction to earnings over the next 12 months. When our derivative financial instruments are settled, the related amount in accumulated other comprehensive income is recorded in the income statement in operating revenues or cost of natural gas and other products, depending on the item being hedged. The effect of reclassifying these amounts to the income statement line items is recording our earnings for the period at the “hedged price” under the derivative financial instruments.

 

We recognize the realized and unrealized gains and losses from our fair value hedge derivative financial instruments associated with our inventory of NGL and NGL products currently in the statements of operations in cost of natural gas and other products.

 

The fair value of our derivative financial instruments at December 31, 2003, 2002 and 2001 are reflected in our balance sheets in other current assets or other current liabilities as appropriate.

 

The counterparties for our hedging activities in 2003 are Gulfstream Trading, Ltd, Duke Energy NGL Services and Morgan Stanley Capital Group Inc. In 2002 and 2001, the counterparty to our hedging activities was El Paso Merchant Energy North America Company. We do not require collateral and do not anticipate non-performance by these counterparties.

 

Note 7—Commitments and Contingencies

 

Environmental

 

We are subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

 

of the disposal or release of specified substances at current and former operating sites. We have approximately $2.2 million and $2.3 million recorded at December 31, 2003 and 2002 for costs associated with remediating discharges of specified substances into the environment.

 

On December 16, 2003, we received a Notice of Enforcement (NoE) from the Texas Commission on Environmental Quality (TCEQ) concerning alleged Clean Air Act violations at our Shoup, Texas plant. The NoE included a draft Agreed Order assessing a penalty of $365,750 for the cited violations. The alleged violation pertains to emission limit exceedences, testing, reporting and recordkeeping issues in 2001. We submitted a response to the TCEQ in February 2004 contesting several of the allegations and the penalty calculation. Resolution of this matter is pending additional discussions with the TCEQ. In December 2003, we accrued for this penalty and reflected the amount in other current liabilities at December 31, 2003. While the outcome of this issue cannot be predicted with certainty, based on current information and our existing accrual, we do not expect the ultimate resolution of this matter to have a material adverse effect on our financial statements.

 

It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. 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 increasingly strict environmental laws, regulations and 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. As new information becomes available, or relevant developments occur, we will review our accruals and make any appropriate adjustments.

 

Note 8—Major Customers

 

The percentage of our revenue from major customers was as follows at December 31:

 

         2003    

        2002    

        2001    

 

Dow Hydrocarbons & Resources Inc

   13 %   —       —    

El Paso Merchant Energy North America Company 1

   16 %   42 %   38 %

Valero Refining—Texas, L. P.

   13 %   10 %   19 %

1 Affiliated company.

 

During 2003 we reduced our transactions with El Paso Merchant Energy North America Company, a subsidiary of El Paso Corporation, and began to replace those transactions with similar arrangements with third parties.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

COMBINED BALANCE SHEETS

(In thousands)

(Unaudited)

 

     June 30,
2004


    December 31,
2003


 
ASSETS                 

Current assets

                

Accounts receivable

                

Trade, net

   $ 138,310     $ 160,475  

Affiliates

     36,566       16,632  

Natural gas imbalance receivable from affiliate

     —         3,022  

Inventory

     11,798       14,964  

Other current assets

     8,421       4,148  
    


 


Total current assets

     195,095       199,241  

Property, plant and equipment, net

     311,145       316,255  
    


 


Total assets

   $ 506,240     $ 515,496  
    


 


LIABILITIES AND OWNERS’ NET INVESTMENT                 

Current liabilities

                

Accounts payable

                

Trade

   $ 111,382     $ 128,638  

Affiliates

     66,888       48,442  

Natural gas imbalance payable to affiliate

     3,512       —    

NGL and NGL product liabilities

     14,457       14,213  

Other current liabilities

     1,430       2,623  
    


 


Total current liabilities

     197,669       193,916  

Environmental liabilities

     1,981       2,190  
    


 


Total liabilities

     199,650       196,106  
    


 


Commitments and contingencies

                

Accumulated other comprehensive loss

     (32 )     (32 )

Owners’ net investment

     306,622       319,422  
    


 


Total owners’ net investment

     306,590       319,390  
    


 


Total liabilities and owners’ net investment

   $ 506,240     $ 515,496  
    


 


 

See accompanying notes.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

COMBINED STATEMENTS OF OPERATIONS

(In thousands)

(Unaudited)

 

     For the Six Months Ended
June 30,


 
            2004       

          2003       

 

Operating revenues

               

Sales of NGL and NGL products

               

Third parties

   $ 643,519    $ 547,891  

Affiliates

     28,370      10,475  

Processing and other services

               

Third parties

     17,176      8,384  

Affiliates

     96,238      178,522  
    

  


       785,303      745,272  
    

  


Operating expenses

               

Cost of natural gas and other products

               

Third parties

     452,258      468,746  

Affiliates

     289,484      277,948  

Operations and maintenance

               

Third parties

     6,926      8,983  

Affiliates

     4,423      3,689  

Depreciation and amortization

     6,201      6,030  

Taxes other than income

     1,190      1,181  
    

  


       760,482      766,577  
    

  


Operating income (loss)

     24,821      (21,305 )

Other expense

     26      107  
    

  


Net income (loss)

   $ 24,795    $ (21,412 )
    

  


 

See accompanying notes.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

COMBINED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

 

     For the Six Months Ended
June 30,


 
           2004      

          2003      

 

Cash flows from operating activities

                

Net income (loss)

   $ 24,795     $ (21,412 )

Adjustments to reconcile net income to cash from operating activities

                

Depreciation and amortization

     6,201       6,030  

Asset and liability changes

                

Accounts receivable

     2,231       24,189  

Natural gas imbalances with affiliate

     6,534       (4,617 )

Inventory

     3,081       (1,396 )

Other current assets

     (4,273 )     (2,823 )

Accounts payable

     1,190       (12,257 )

NGL and NGL product liabilities

     244       9,911  

Other current liabilities

     (1,108 )     (114 )

Decrease in environmental liabilities

     (209 )     (84 )
    


 


Net cash provided by (used in) operating activities

     38,686       (2,573 )
    


 


Cash flows from investing activities

                

Capital expenditures

     (1,091 )     (1,075 )
    


 


Net cash used in investing activities

     (1,091 )     (1,075 )
    


 


Cash flows from financing activities

                

Net cash contributions from (distributions to) owners

     (37,595 )     3,648  
    


 


Net cash provided by (used in) financing activities

     (37,595 )     3,648  
    


 


Net change in cash and cash equivalents

     —         —    

Cash and cash equivalents

                

Beginning of period

     —         —    
    


 


End of period

   $ —       $ —    
    


 


 

See accompanying notes.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

COMBINED STATEMENTS OF COMPREHENSIVE INCOME

AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME

(In thousands)

(Unaudited)

 

Comprehensive income

 

     For the Six Months Ended
June 30,


 
         2004      

       2003      

 

Net income (loss)

   $ 24,795    $ (21,412 )

Other comprehensive income (loss)

     —        (50 )
    

  


Total comprehensive income (loss)

   $ 24,795    $ (21,462 )
    

  


 

Accumulated Other Comprehensive Income

 

     For the Six
Months
Ended
June 30,
2004


    For the Year
Ended
December 31,
2003


 

Beginning balance

   $ (32 )   $ 50  

Unrealized mark-to-market gains on cash flow hedges arising during the period

     333       2,657  

Reclassification adjustments for changes in initial value of derivative instruments to settlement date

     (333 )     (2,739 )
    


 


Ending balance

   $ (32 )   $ (32 )
    


 


 

See accompanying notes.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS

(Unaudited)

 

Note 1—Organization and Nature of Business

 

Organization

 

El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. are Delaware limited partnerships, whose limited and general partnership interests are owned by subsidiaries of El Paso Corporation. We own and operate assets located in south Texas, including nine cryogenic processing plants and related equipment with total processing capacity of 1,890 million cubic feet per day (MMcf/d), one natural gas treating plant with capacity of 150 MMcf/d, a 294-mile natural gas gathering system and a 3.8-mile natural gas liquids (NGL) pipeline. We gather natural gas, extract NGL from natural gas, process mixed NGL into component products (e.g., ethane, propane, butane, natural gasoline, and other products), and transport and market NGL and NGL products.

 

The terms “we,” “our” or “us” refer to El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. on a combined basis.

 

Sale to Enterprise Products Partners, L.P.

 

In December 2003, certain subsidiaries of El Paso Corporation entered into an agreement to sell their interest in us to Enterprise Products Operating, L.P. (Enterprise) for approximately $150 million. The sale is expected to close concurrent with the closing of the merger of a subsidiary of Enterprise Products Partners, L.P. with GulfTerra Energy Partners, L.P. (GulfTerra), both of which are master limited partnerships. Until the closing of the sale or termination of the agreement, we may not, without Enterprise’s consent, engage in any action outside the ordinary course of business. As a result, our ability to incur liens, amend or terminate material agreements, issue equity, incur debt, sell assets, initiate or settle litigation, or change our accounting principles is limited. The parties’ obligations under the agreement to sell us are subject to the satisfaction of specified conditions including, among other things, obtaining Hart-Scott-Rodino and other third party approvals and consents and consummating the merger.

 

Note 2—Significant Accounting Policies

 

The accompanying combined financial statements have been prepared from El Paso Corporation’s historical accounting records of the combined companies and are presented on a carve-out basis to include the historical operations applicable to El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. In this context, no direct owner relationship existed among these entities. Accordingly, the net investment in these entities (owners’ net investment) is shown in lieu of owners’ equity in the combined financial statements.

 

Our combined financial statements are prepared on the accrual basis of accounting in conformity with accounting principles generally accepted in the United States of America. All significant intercompany accounts and transactions within the companies have been eliminated.

 

The financial statements as of June 30, 2004 and for the six months ended June 30, 2004 and 2003, are unaudited. We derived the balance sheet as of December 31, 2003, from our audited financial statements. In management’s opinion all adjustments necessary to fairly present operating results, financial position and cash flows are reflected in the interim periods presented, all of which are of a normal, recurring nature. Information for interim periods may not depict the results of operations for the entire year.

 

Throughout the periods covered by the combined financial statements, El Paso Corporation and its subsidiaries have provided cash management services to us through a centralized treasury system. As a result, all

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

of our charges and cost allocations covered by the centralized treasury system were deemed to have been paid by us to El Paso Corporation and its subsidiaries, in cash, during the period in which the cost was recorded in the combined financial statements. In addition, all of our cash receipts were advanced to El Paso Corporation and its subsidiaries as they were received. As a result of using these centralized treasury systems, the excess of cash receipts advanced over the charges and cash allocation is reflected as net cash contributions from/distributions to our owners in the combined statements of owners’ net investment and cash flows.

 

We have been allocated general and administrative expenses incurred by our owners in order to present our financial statements on a stand-alone basis. See Note 4 for a discussion of the amounts and method of allocation. All of the allocations in the combined financial statements are based on assumptions that management believes are reasonable under the circumstances. However, these allocations are not necessarily indicative of the costs and expenses that would have resulted had we operated as a separate entity.

 

Use of Estimates

 

The preparation of these combined financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosures in these combined financial statements. While we believe these estimates are appropriate, actual results can, and often do, differ from those estimates.

 

Allowance for Doubtful Accounts

 

We have established an allowance for losses on accounts that we believe are uncollectible. We regularly review the collectibility of our accounts and adjust the allowance as necessary, primarily under the specific identification method. At June 30, 2004 and December 31, 2003, the allowance was approximately $2.4 million and $2.0 million.

 

Natural Gas Imbalance

 

The natural gas imbalance results from differences in gas volumes we purchased and sold or consumed in our processing activities compared with the amounts we nominated for delivery. This imbalance is settled in kind through a tracking mechanism or a negotiated cash-out between parties and is valued at prices representing the estimated value of these imbalances upon settlement. Changes in natural gas prices will affect our valuation. We do not value our imbalances based on current month-end spot prices because it is not likely that we would purchase or receive natural gas at that point in time to settle the imbalance. Natural gas imbalances are reflected in imbalance receivable or imbalance payable, as appropriate, in our combined financial statements.

 

Inventory

 

Our inventory consists of NGL and NGL products and is valued at the lower of its cost or market with cost determined using the average cost method. We had no lower of cost or market adjustments for the six month periods ended June 30, 2004 and 2003.

 

Property, Plant and Equipment

 

Our processing and treating plants, as well as our natural gas gathering and NGL pipelines are recorded at historical cost. Provision for depreciation of property, plant and equipment is made on a straight-line basis over

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

the estimated useful lives of these facilities using periods ranging from 30 to 40 years. Retirements, sales and disposals of assets are recorded by eliminating the related cost and accumulated depreciation of the disposed assets with any resulting gains or losses reflected in income. Repairs and maintenance costs are expensed as incurred, while additions, improvements and replacements are capitalized.

 

Accounting for Asset Retirement Obligations

 

In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations. This statement requires companies to record a liability for the estimated retirement and removal of assets used in their business. The liability is recorded at its fair value, with a corresponding asset which is depreciated over the remaining useful life of the long-lived asset to which the liability relates.

 

On January 1, 2003, we adopted the provisions of SFAS No. 143. Our assets subject to asset retirement obligations include two of our processing plants, our natural gas gathering system and a portion of our NGL pipeline. We have identified these assets as having an indeterminate life in accordance with SFAS No. 143, which means that we cannot reasonably estimate the fair value of the retirement obligations. Accordingly, we did not recognize any asset or related liability for the cost of retiring or removing long-lived assets used in our business upon our adoption of SFAS No. 143. A liability for these asset retirement obligations will be recorded if and when the fair value of these obligations becomes measurable. Our estimate of the potential costs that would be required to settle these obligations if they were settled in the near term range from $6.2 million to $10.6 million.

 

Impairment and Disposal of Long-Lived Assets

 

We apply the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, to account for impairment and disposal of long-lived assets. Accordingly, we evaluate the recoverability of selected long-lived assets when adverse events or changes in circumstances indicate that the carrying value of an asset or group of assets may not be recoverable. We determine the recoverability of an asset or group of assets by estimating the undiscounted cash flows expected to result from the use and eventual disposition of the asset or group of assets at the lowest level for which separate cash flows can be measured. If the total of the undiscounted cash flows is less than the carrying amount for the assets, we estimate the fair value of the asset or group of assets and recognize the amount by which the carrying value exceeds the fair value, less cost to sell, as an impairment loss in income from operations in the period the impairment is determined.

 

Additionally, as required by SFAS No. 144, we classify long-lived assets to be disposed of other than by sale (e.g., abandonment, exchange or distribution) as held and used until the item is abandoned, exchanged or distributed. We evaluate assets to be disposed of other than by sale for impairment and recognize a loss for the excess of the carrying value over the fair value. Long-lived assets to be disposed of through sale recognition meeting specific criteria are classified as held for sale and measured at the lower of their cost or fair value less cost to sell. We report the results of operations of a component classified as held for sale, including any gain or loss in the period(s) in which they occur. We classify gains and losses resulting from the sale of long-lived assets in operating income in accordance with the provisions of SFAS No. 144. We also reclassify the asset or assets as either held for sale or discontinued operations, depending on whether they have independently determinable cash flow and whether we have any continuing involvement.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

NGL and NGL Product Liabilities

 

We record NGL and NGL product liabilities when we deliver more NGL and NGL products to customers than is available in our inventory. To accomplish these deliveries, we borrow the inventory of third parties in our possession and then must settle the liability by restoring the inventory. We value the liability at the appropriate index price based on location and the type of product borrowed.

 

Fair Value of Financial Instruments

 

As of June 30, 2004 and December 31, 2003 our carrying amounts of accounts receivable and accounts payable approximate fair value due to the short-term nature of these instruments.

 

Revenue Recognition

 

Revenue from processing services is recognized in the period the natural gas is processed for the customer. Our processing contracts generally provide that we are compensated for our services from the retention of NGL extracted, fee-based terms and the sale of natural gas purchased for and not consumed in our processing activities. Revenues from NGL sales contracts, including the sale of NGL retained from processing, are recognized as sales of NGL and NGL products in our combined statements of operations and recorded upon the delivery of the NGL products specified in each individual contract. Pricing terms in these sales contracts are based upon market-related prices for such products and can include pricing differentials due to factors such as differing delivery locations and markets.

 

Cost of Natural Gas and Other Products

 

In providing our processing services, we incur and are responsible for costs based on the type of processing contracts. These costs include producer payments based on contracts which require us to pay the producer an amount for liquids extracted at a stated contract price, natural gas replacement costs, liquid fractionation costs and natural gas purchase costs.

 

Accounting for Price Risk Management Activities

 

Our business activities expose us to a variety of risks including commodity price risk. From time to time we engage in price risk management activities for non-trading purposes to manage market risks associated with the commodities we purchase and sell. Our price risk management activities involve the use of a variety of derivative financial instruments, including

 

    exchange-traded futures contracts that involve cash settlement;

 

    forward contracts that involve cash settlements or physical delivery of a commodity; and

 

    swap contracts that require payments to (or receipts from) counterparties based on the difference between a fixed and a variable price, or two variable prices, for a commodity.

 

We account for all of our derivative instruments in accordance with the provisions of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. We record all derivatives in our combined balance sheets at their fair value as other assets or other liabilities and classify them as current or noncurrent based upon their anticipated settlement date.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

For those instruments entered into to hedge risk and which qualify as hedges, we apply the provisions of SFAS No. 133, and the accounting treatment depends on our intended use for each instrument and its designation. In addition to its designation, a hedge must be effective. To be effective, changes in the value of the derivative or its resulting cash flows must substantially offset changes in the value or cash flows of the item being hedged.

 

We formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives and strategies for undertaking various hedge transactions. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows or fair values of the hedged items. We discontinue hedge accounting prospectively if we determine that a derivative is not highly effective as a hedge or if we decide to discontinue the hedging relationship.

 

During 2004 and 2003, we entered into both cash flow and fair value hedges that qualify for hedge accounting under SFAS No. 133. Changes in the fair value of a derivative designated as a cash flow hedge are recorded in accumulated other comprehensive income for the portion of the change in value of the derivative that is effective. The ineffective portion of the derivative is recorded in earnings in the current period. Classification in the combined income statement of the ineffective portion is based on the income classification of the item being hedged. At the date of the hedged transaction, we reclassify the gains or losses resulting from the sale, maturity, extinguishment or termination of derivative instruments designated as hedges from accumulated other comprehensive income to operating income in our combined statements of operations. For fair value hedges, changes in the fair value of the derivative and changes in the fair value of the related asset or liability associated with the hedged risk are recorded in our current period earnings, generally as a component of operating revenues in the case of a sale, or as a component of the cost of natural gas and other products in the case of a purchase. We classify cash inflows and outflows associated with the settlement of our derivative transactions as cash flows from operating activities in our combined statements of cash flows.

 

We may also purchase and sell instruments to economically hedge price fluctuations in the commodity markets. These instruments are not documented as hedges due to their short-term nature, or do not qualify under the provisions of SFAS No. 133 for hedge accounting due to the terms of the instruments. Where such derivatives do not qualify, or are not documented as a hedge, changes in their fair value are recorded in earnings in the current period.

 

During the normal course of our business, we may enter into contracts that qualify as derivatives under the provisions of SFAS No. 133. As a result, we evaluate our contracts to determine whether derivative accounting is appropriate. Contracts that meet the criteria of a derivative and qualify as “normal purchase” and “normal sales,” as those terms are defined in SFAS No. 133, may be excluded from SFAS No. 133.

 

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This statement amends SFAS No. 133 to incorporate several interpretations of the Derivatives Implementation Group (DIG), and also makes several minor modifications to the definition of a derivative as it was defined in SFAS No. 133. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003. Our combined financial statements were not initially affected by adopting this standard, although the FASB and DIG continue to deliberate on the application of the standard to certain derivative contracts, which may affect our combined financial statements in the future.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Environmental Costs and Other Contingent Liabilities

 

We expense or capitalize expenditures for ongoing compliance with environmental regulations that relate to past or current operations as appropriate. We expense amounts for clean-up of existing environmental contamination caused by past operations that do not significantly increase the value of the property or extend its useful life. We record liabilities when our environmental assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency or other organizations. These estimates are subject to revision in future periods based on actual costs or new circumstances and are included in our combined balance sheets at their undiscounted amounts. We currently have a reserve for environmental matters.

 

We are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we will establish the necessary accruals. As of June 30, 2004 and December 31, 2003 we did not have any reserves for pending or threatened legal matters.

 

Income Taxes

 

We are organized as limited partnerships and are therefore, not subject to taxation for federal or state income tax purposes. The taxable income or loss resulting from our operations will ultimately be included in the federal and state income tax returns of our owners. Accordingly, no provision for income taxes has been recorded in the accompanying combined financial statements.

 

Comprehensive Income

 

Our comprehensive income is determined based on net income, adjusted for changes in accumulated other comprehensive income (loss) from our cash flow hedging activities.

 

Recent Pronouncements

 

Consolidation of Variable Interest Entities

 

We adopted the provisions of FASB Interpretation (FIN) No. 46, Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51 as revised by FIN No. 46-R, during the first quarter of 2004. This interpretation defines a variable interest entity (VIE) as a legal entity whose equity owners do not have sufficient equity at risk and/or a controlling financial interest in the entity. This standard requires that a company consolidate a VIE if it is allocated a majority of the VIE’s losses and/or returns, including fees paid by the entity. Our adoption of FIN No. 46 had no effect on our reported results or financial position.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Note 3—Property, Plant and Equipment

 

Our property, plant and equipment consist of the following (in thousands):

 

    

June 30,

2004


    December 31,
2003


 

Property, plant and equipment at cost

                

Processing plants, pipelines and related facilities

   $ 356,683     $ 354,815  

Construction work-in-progress

     819       1,596  
    


 


       357,502       356,411  

Less accumulated depreciation, depletion and amortization

     (46,357 )     (40,156 )
    


 


Total property, plant and equipment, net

   $ 311,145     $ 316,255  
    


 


 

Note 4—Related Party Transactions

 

We enter into various types of transactions with affiliates in the normal course of business on market-related terms and conditions including processing of natural gas for, selling natural gas and NGL products to and purchasing natural gas and NGL products from affiliates. In addition, our owners allocate to us general and administrative costs incurred on our behalf. Our allocation is based on an average rate representing our gross property, plant and equipment; earnings before interest and taxes; and direct labor costs, each expressed as a percentage of the total amount recorded by El Paso Corporation. We were allocated general and administrative costs of approximately $3.8 million and $2.9 million for the six months ended June 30, 2004 and 2003, which are included in operations and maintenance expense in our combined statements of operations.

 

Substantially all of the individuals who perform the day-to-day financial, administrative, accounting and operational functions for us, as well as those who are responsible for directing and controlling us, are currently employed by El Paso Corporation. Eligible employees participate in benefit plans provided by El Paso Corporation which include a defined benefit pension plan, a defined contribution plan covering substantially all domestic employees and health care benefit plans. Costs associated with these plans are proportionately allocated to us at 32 percent of the direct labor allocation associated with our operation. For the six month periods ended June 30, 2004 and 2003, these allocated costs were approximately $0.6 million and $0.8 million which are included in operations and maintenance expense in our combined statements of operations.

 

The following table provides summary data of our transactions with related parties for the six months ended June 30 (in thousands):

 

     2004

   2003

Revenues received from related parties:

             

Sales of NGL and NGL products

   $ 28,370    $ 10,475

Processing and other services

     96,238      178,522
    

  

     $ 124,608    $ 188,997
    

  

Expenses paid to related parties:

             

Cost of natural gas and other products

   $ 289,484    $ 277,948

Operations and maintenance

     4,423      3,689
    

  

     $ 293,907    $ 281,637
    

  

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

For the six months ended June 30, 2004 and 2003, revenues received from related parties comprised approximately 16 percent and 25 percent of our operating revenues. During 2003, we began reducing our transactions with El Paso Merchant Energy North America Company and began to replace those transactions with similar arrangements with third parties. Additionally, in the last quarter of 2003, certain businesses previously operated by El Paso Merchant Energy with which we regularly sell NGL and NGL products, processing and other services began operating under El Paso Field Services, further reducing our transactions with El Paso Merchant Energy.

 

As part of the purchase and sale agreement with Enterprise Products Operating, L.P., El Paso Field Services will retain El Paso NGL Marketing’s south Louisiana and Rocky Mountains market activities. In June 2004, El Paso NGL Marketing began selling NGL and NGL products to El Paso Gas Liquids Marketing, L.L.C., a recently formed subsidiary of El Paso Field Services. El Paso Gas Liquids Marketing was formed to provide spot marketing services for NGL and NGL products to the third party customers in the south Louisiana and Rocky Mountains markets previously served by El Paso NGL Marketing.

 

The following table provides summary data categorized by our related parties for the six months ended June 30 (in thousands):

 

     2004

    2003

Revenues received from related parties:

              

El Paso Corporation

              

El Paso Merchant Energy North America Company

   $ 2,763     $ 180,988

El Paso Field Services

     112,608       4,561

El Paso Production Company

     4,101       3,121

GulfTerra Energy Partners, L.P.

     5,136       327
    


 

     $ 124,608     $ 188,997
    


 

Cost of natural gas and other products:

              

El Paso Corporation

              

El Paso Field Services

   $ 202,568     $ 173,431

El Paso Production Company

     50,198       23,991

Colorado Interstate Gas Company

     15,065       10,823

El Paso Merchant Energy North America Company

     (3,133 )     43,237

GulfTerra Energy Partners, L.P.

     24,786       26,466
    


 

     $ 289,484     $ 277,948
    


 

Operating expenses paid to related parties:

              

El Paso Field Services

   $ 4,423     $ 3,689
    


 

 

In May 2004, El Paso NGL Marketing Company and El Paso Merchant Energy North America Company agreed to a settlement of $3 million related to prior period liquid costs. The settlement arose from the resolution, under the terms of its sales agreement, of disputed volumes of liquids purchased in prior years by El Paso NGL Marketing from El Paso Merchant Energy. We have recorded the settlement as a reduction to cost of natural gas and other products, in the combined statement of operations for the six months ended June 30, 2004.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Our accounts receivable due from and accounts payable due to related parties consisted of the following (in thousands):

 

    

June 30,

2004


    December 31,
2003


Accounts receivable

              

El Paso Corporation

              

El Paso Field Services

   $ 34,373     $ 14,595

El Paso Merchant Energy North America Company

     15       425

El Paso Production Company

     404       736

GulfTerra Energy Partners, L.P.

     1,774       876
    


 

     $ 36,566     $ 16,632
    


 

Natural gas imbalance receivable (payable)

              

GulfTerra Energy Partners, L.P.

   $ (3,512 )   $ 3,022
    


 

Accounts payable

              

El Paso Corporation

              

El Paso Field Services

   $ 46,872     $ 33,719

El Paso Production Company

     6,597       9,281

Colorado Interstate Gas Company

     3,685       1,603

El Paso Merchant Energy North America Company

     87       87

GulfTerra Energy Partners, L.P.

     9,647       3,752
    


 

     $ 66,888     $ 48,442
    


 

 

Note 5—Accounting for Hedging Activities

 

A majority of our commodity purchases and sales, which relate to sales of NGL and NGL products associated with our processing and marketing activities, are at spot market or forward market prices. We use futures, forward contracts and swaps to limit our exposure to fluctuations in the commodity markets and allow for a fixed cash flow stream from our natural gas and NGL processing and marketing activities and to limit our exposure to commodity price fluctuations in our inventory of NGL and NGL products.

 

In connection with some of our processing activities, we are compensated by sharing in the value of the NGLs that are extracted as part of the processing activities. We entered into fixed for floating cash flow hedge transactions to provide stable cash flows from the anticipated sales for some of these NGL and NGL products. Additionally, we enter into fixed for floating fair value hedge transactions to protect the value of a portion of our NGL and NGL products in our existing inventory. We generally enter into hedge transactions for periods not exceeding 18 months and no ineffectiveness exists in our hedging relationships because all purchase and sale prices are based on the same index and volumes as the hedge transactions.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

The following table presents information about our hedging activities:

 

     June 30,
2004


    December 31,
2003


 

Cash Flow Hedges

                

Commodity Price Swaps

                

Number of open contracts

     5       5  

Contract expiration

     1 month      
 
1
month
 
 

Contract volumes (Mbbls)

     70       46  

Weighted average price received (per bbl)

   $ 26.45     $ 25.49  

Weighted average price paid (per bbl)

   $ 26.90     $ 26.18  

Swap fair value asset (liability) (in thousands)

   $ (32 )   $ (32 )

 

     December 31,
2003


     

Fair Value Hedges(1)

            

Commodity Price Swaps

            

Number of open contracts

     2      

Contract expiration

     1 month      

Contract volumes (Mbbls)

     20      

Weighted average price received (per bbl)

   $ 23.73      

Weighted average price paid (per bbl)

   $ 28.04      

Swap fair value asset (liability) (in thousands)

   $ (86 )    

bbl = barrel
Mbbl = thousands of barrels
(1) We had no open contracts representing fair value hedges at June 30, 2004.

 

We estimate the entire $32,000 of unrealized losses included in other comprehensive income at June 30, 2004, will be reclassified from accumulated other comprehensive income as a decrease to earnings over the next 12 months. When our derivative financial instruments are settled, the related amount in accumulated other comprehensive income is recorded in the combined income statement in operating revenues or cost of natural gas and other products, depending on the item being hedged. The effect of reclassifying these amounts to the combined income statement line items is recording our earnings for the period at the hedged price under the derivative financial instruments.

 

We recognize the realized and unrealized gains and losses from our fair value hedge derivative financial instruments associated with our inventory of NGL and NGL products currently in the statements of operations in cost of natural gas and other products. We recognized losses of approximately $150,000 and $145,000 during the six month periods ended June 30, 2004 and 2003.

 

The fair value of our derivative financial instruments at June 30, 2004 and December 31, 2003 as disclosed above are reflected in our combined balance sheets in other current assets or other current liabilities as appropriate.

 

The counterparties for our hedging activities in 2004 and 2003 are Gulfstream Trading, Ltd, Duke Energy NGL Services and Morgan Stanley Capital Group Inc. We do not require collateral and do not anticipate non-performance by these counterparties.

 

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Index to Financial Statements

EL PASO HYDROCARBONS, L.P.

EL PASO NGL MARKETING COMPANY, L.P.

 

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

 

Note 6—Commitments and Contingencies

 

Environmental

 

We are subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. We have approximately $2.0 million and $2.2 million recorded at June 30, 2004 and December 31, 2003 for costs associated with remediating discharges of specified substances into the environment.

 

On December 16, 2003, we received a Notice of Enforcement (NoE) from the Texas Commission on Environmental Quality (TCEQ) concerning alleged Clean Air Act violations at our Shoup, Texas plant. The NoE included a draft Agreed Order assessing a penalty of $365,750 for the cited violations. The alleged violation pertains to emission limit exceedences, testing, reporting and recordkeeping issues in 2001. We submitted a response to the TCEQ in February 2004 contesting several of the allegations and the penalty calculation. Resolution of this matter is pending additional discussions with the TCEQ. We have accrued for this penalty and reflected the amount in other current liabilities in our combined balance sheets. While the outcome of this issue cannot be predicted with certainty, based on current information and our existing accrual, we do not expect the ultimate resolution of this matter to have a material adverse effect on our combined financial statements.

 

It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. 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 increasingly strict environmental laws, regulations and 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. As new information becomes available, or relevant developments occur, we will review our accruals and make any appropriate adjustments.

 

Note 7—Major Customers

 

The percentage of our revenue from major customers was as follows at June 30:

 

     2004

    2003

 

Dow Hydrocarbons & Resources Inc

   16.6 %   12.3 %

El Paso Merchant Energy North America Company 1

   0.4 %   24.3 %

Valero Refining—Texas, L. P.

   14.5 %   12.6 %

El Paso Field Services 1

   14.3 %   0.6 %

1 Affiliated company.

 

During 2003, we reduced our transactions with El Paso Merchant Energy North America Company, a subsidiary of El Paso Corporation, and began to replace those transactions with similar arrangements with third parties.

 

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Index to Financial Statements

Appendix A

 

Form of Amended and Restated Agreement of Limited Partnership

 

A-1


Table of Contents
Index to Financial Statements

 

12,000,000 Units

Representing Limited Partner Interests

 

LOGO

 


 

PROSPECTUS

 

                    , 2005

 


 

Joint Book-Running Managers

 

Citigroup

Lehman Brothers

 

Until                     , 2005 (25 days after the date of this prospectus), all dealers that buy, sell or trade our units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealer’s obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.


Table of Contents
Index to Financial Statements

PART II

 

INFORMATION NOT REQUIRED IN THE PROSPECTUS

 

Item 13. Other Expenses of Issuance and Distribution.

 

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee and the NYSE listing fee, the amounts set forth below are estimates.

 

Commission registration fee

   $ 46,434

NASD filing fee

     39,951

NYSE listing fee

     250,000

Printing and engraving expenses

     750,000

Fees and expenses of legal counsel

     500,000

Accounting fees and expenses

     650,000

Structuring fees

     1,000,000

Transfer agent and registrar fees

     *

Miscellaneous

     *
    

Total

   $ 3,500,000
    


* To be provided by amendment.

 

Item 14. Indemnification of Directors and Officers.

 

The section of the prospectus entitled “Description of Our Partnership Agreement—Indemnification” is incorporated herein by this reference. Reference is also made to the Underwriting Agreement to be filed as Exhibit 1.1 to this registration statement. Subject to any terms, conditions or restrictions set forth in the Partnership Agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.

 

Section 18-108 of the Delaware Limited Liability Company Act provides that, subject to such standards and restrictions, if any, as are set forth in its limited liability company agreement, a Delaware limited liability company may, and shall have the power to, indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. The limited liability company agreement of EPE Holdings, LLC provides for the indemnification of (i) present or former members of the Board of Directors of EPE Holdings, LLC or any committee thereof, (ii) present or former officers, employees, partners, agents or trustees of EPE Holdings, LLC or (iii) persons serving at the request of EPE Holdings, LLC in another entity in a similar capacity as that referred to in the immediately preceding clauses (i) or (ii) (each, a “General Partner Indemnitee”) to the fullest extent permitted by law, from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including reasonable legal fees and expenses), judgments, fines, penalties, interest, settlements and other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any such person may be involved, or is threatened to be involved, as a party or otherwise, by reason of such person’s status as a General Partner Indemnitee; provided, that in each case the General Partner Indemnitee acted in good faith and in a manner which such General Partner Indemnitee believed to be in, or not opposed to, the best interests of EPE Holdings, LLC and, with respect to any criminal proceeding, had no reasonable cause to believe such General Partner Indemnitee’s conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere, or its equivalent, shall not create a presumption that the General Partner Indemnitee acted in a manner contrary to that specified above. Any indemnification pursuant to these provisions shall be made only out of the assets of EPE Holdings, LLC. EPE Holdings, LLC is authorized to purchase and maintain insurance, on behalf of the members of its Board of Directors, its officers and such other

 

II-1


Table of Contents
Index to Financial Statements

persons as the Board of Directors may determine, against any liability that may be asserted against or expense that may be incurred by such person in connection with the activities of EPE Holdings, LLC, regardless of whether EPE Holdings, LLC would have the power to indemnify such person against such liability under the provisions of its limited liability company agreement.

 

Item 15. Recent Sales of Unregistered Securities.

 

On April 22, 2005, in connection with the formation of Enterprise GP Holdings L.P., Enterprise GP Holdings L.P. issued to (i) EPE Holdings, LLC the 0.01% general partner interest for $0.10, (ii) Duncan Family Interests, Inc. a 95% limited partner interest for $950.00 and (iii) Dan Duncan LLC a 4.99% limited partner interest in the partnership for $49.90 in an offering exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

 

Item 16. Exhibits

 

The following documents are filed as exhibits to this registration statement. With respect to exhibits that are incorporated by reference to Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323.

 

Exhibit
Number


       

Description


1.1*       Form of Underwriting Agreement
3.1**       Certificate of Limited Partnership of Enterprise GP Holdings L.P.
3.2*       Form of Amended and Restated Agreement of Limited Partnership of Enterprise GP Holdings L.P. (included as Appendix A to the Prospectus)
3.3**       Certificate of Formation of EPE Holdings, LLC
3.4*       Form of Amended and Restated Limited Liability Company Agreement of EPE Holdings, LLC
4.1**       Specimen certificate representing units
4.2       Fourth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of October 1, 2004 (incorporated by reference to Exhibit 3.1 to Enterprise Products Partners L.P.’s Form 8-K filed October 6, 2004).
4.3       Second Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, among Duncan Family Interests, Inc., Dan Duncan LLC, and GulfTerra GP Holding Company dated September 30, 2004 (incorporated by reference to Exhibit 3.1 to Enterprise Products Partners L.P.’s Form 8-K filed September 30, 2004).
4.4       Application for Admission by Enterprise GP Holdings L.P. as a Substituted Member of Enterprise Products GP, LLC (incorporated by reference to Exhibit 3.1 to Enterprise Products Partners L.P.’s Form 8-K filed January 18, 2005).
4.5       Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (restated to include all agreements through December 10, 2003) (incorporated by reference to Exhibit 3.3 to Enterprise Products Partners L.P.’s Form 10-Q filed August 9, 2004).
4.6       Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed March 10, 2000).
4.7       First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners L.P.’s Registration Statement on Form S-4 filed January 28, 2003).

 

II-2


Table of Contents
Index to Financial Statements
Exhibit
Number


       

Description


4.8       Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners L.P.’s Registration Statement on Form S-4 filed January 28, 2003).
4.9       Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Form 10-K filed March 31, 2003).
4.10       Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Enterprise Products Partners L.P.’s Form 10-K filed March 31, 2003).
4.11       Global Notes representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed January 25, 2001).
4.12       Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit “B” to Tejas Energy, LLC’s Schedule 13D filed September 27, 1999).
4.13       Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “E” to Tejas Energy, LLC’s Schedule 13D filed September 27, 1999).
4.14       Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “C” to Tejas Energy, LLC’s Schedule 13D filed September 27, 1999).
4.15       Amendment No. 1, dated September 12, 2003, to Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed September 15, 2003).
4.16       Agreement dated as of March 4, 2004 among Enterprise Products Partners L.P., Shell US Gas & Power LLC and Kayne Anderson MLP Investment Company (incorporated by reference to Exhibit 4.31 to Enterprise Products Partners L.P.’s Form S-3 Registration Statement filed March 4, 2004).
4.17       $750 Million Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, CitiBank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents, Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents, Wachovia Capital Markets, LLC, CitiGroup Global Markets Inc. and JPMorgan Chase Securities, Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed on August 30, 2004).
4.18       Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.1, above (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners L.P.’s Form 8-K filed on August 30, 2004).
4.19       $2.25 Billion 364-Day Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, CitiCorp North America, Inc. and Lehman Commercial Paper Inc., as Co-Syndication Agents, JPMorgan Chase Bank, UBS Loan Finance LLC and Morgan Stanley Senior Funding, Inc., as Co-Documentation Agents, Wachovia Capital Markets, LLC, CitiGroup Global Markets Inc. and Lehman Brothers Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Form 8-K filed on August 30, 2004).

 

II-3


Table of Contents
Index to Financial Statements
Exhibit
Number


       

Description


4.20       Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.3, above (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners L.P.’s Form 8-K filed on August 30, 2004).
4.21       Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).
4.22       First Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).
4.23       Second Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).
4.24       Third Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).
4.25       Fourth Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).
4.26       Global Note representing $500 million principal amount of 4.000% Series B Senior Notes due 2007 with attached Guarantee (incorporated by reference to Exhibit 4.14 to Enterprise Products Partners L.P.’s Form S-3 Registration Statement filed on March 4, 2005).
4.27       Global Note representing $500 million principal amount of 4.625% Series B Senior Notes due 2009 with attached Guarantee (incorporated by reference to Exhibit 4.27 to Enterprise Products Partners L.P.’s Form 10-K filed on March 15, 2005).
4.28       Global Note representing $500 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Enterprise Products Partners L.P.’s Form S-3 Registration Statement filed on March 4, 2005).
4.29       Global Note representing $150 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Enterprise Products Partners L.P.’s Form S-3 Registration Statement filed on March 4, 2005).
4.30       Global Note representing $350 million principal amount of 6.650% Series A Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Enterprise Products Partners L.P.’s Form S-3 Registration Statement filed on March 4, 2005.)
4.31       Registration Rights Agreement dated as of October 4, 2004, among Enterprise Products Operating L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.17 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).

 

II-4


Table of Contents
Index to Financial Statements
Exhibit
Number


       

Description


4.32       Fifth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners L.P.’s Form 8-K filed on March 3, 2005).
4.33       Sixth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Form 8-K filed on March 3, 2005).
4.34       Rule 144A Global Note representing $250,000,000 principal amount of 5.00% Series A Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners L.P.’s Form 8-K filed on March 3, 2005).
4.35       Rule 144A Note representing $250,000,000 principal amount of 5.75% Series A Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Enterprise Products Partners L.P.’s Form 8-K filed on March 3, 2005).
4.36       Registration Rights Agreement dated as of March 2, 2005, among Enterprise Products Partners, L.P., Enterprise Products Operating L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.6 to Enterprise Products Partners L.P.’s Form 8-K filed on March 3, 2005).
4.37       Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed on July 1, 2005).
5.1*       Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1*       Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1*       Credit Facility
10.2*       Form of Third Amended and Restated Administrative Services Agreement
10.3       Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners L.P.’s Form 8-K filed September 26, 2000).
10.4       Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners L.P.’s Form 8-K filed February 8, 2002.)
10.5       Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Enterprise Products Partners L.P.’s Form 8-K filed February 8, 2002).
10.6       Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Enterprise Products Partners L.P.’s Form 8-K filed August 12, 2002).
10.7       Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners L.P.’s Form 8-K filed August 12, 2002).
10.8       Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners L.P.’s Form 8-K filed December 15, 2003).

 

II-5


Table of Contents
Index to Financial Statements
Exhibit
Number


       

Description


10.9       Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners L.P.’s Form 8-K filed September 7, 2004).
10.10       Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Enterprise Products Partners L.P.’s Form 8-K filed December 15, 2003).
10.11       Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners L.P.’s Form 8-K filed April 21, 2004).
10.12       Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003 (incorporated by reference to Exhibit 2.3 to Enterprise Products Partners, L.P.’s Form 8-K filed December 15, 2003).
10.13       Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C. adopted by Enterprise Products GTM, LLC as of September 30, 2004 (incorporated by reference to Exhibit 2.11 to Enterprise Products Partners L.P.’s Registration Statement on Form S-4 filed December 27, 2004).
10.14       Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Enterprise Products Partners L.P.’s Form 8-K filed December 15, 2003).
10.15       Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998 (incorporated by reference to Exhibit 10.3 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1/A filed July 8, 1998).
10.16       Partnership Agreement among Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products Company dated May 1, 1992 (incorporated by reference to Exhibit 10.5 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1 filed May 13, 1998).
10.17       Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules Incorporated dated December 13, 1978 (incorporated by reference to Exhibit 10.9 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1 filed May 13, 1998).
10.18       Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas among Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum Company dated July 17, 1985 (incorporated by reference to Exhibit 10.10 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1/A filed July 8,1998).
10.19       Amendment to Propylene Facility and Pipeline Agreement and Propylene Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1993 (incorporated by reference to Exhibit 10.12 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1/A filed July 8, 1998).

 

II-6


Table of Contents
Index to Financial Statements
Exhibit
Number


       

Description


10.20       Amendment to Propylene Facility and Pipeline Agreement and Propylene Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1995 (incorporated by reference to Exhibit 10.13 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1/A filed July 8, 1998).
10.21       Seventh Amendment to Conveyance of Gas Processing Rights, dated as of April 1, 2004 among Enterprise Gas Processing, LLC, Shell Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Consolidated Energy Resources Inc., Shell Land & Energy Company, Shell Frontier Oil & Gas Inc. and Shell Gulf of Mexico Inc. (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners L.P.’s Form 8-K filed April 26, 2004).
10.22       Enterprise Products 1998 Long-Term Incentive Plan, amended and restated as of April 8, 2004 (incorporated by reference to Appendix B to Enterprise Products Partners L.P.’s Notice of Written Consent dated April 22, 2004, filed April 22, 2004).
10.23       Form of Option Grant Award under 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Registration Statement on Form S-8 filed May 19, 2004).
10.24       Form of Restricted Unit Grant under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Registration Statement on Form S-8 filed May 19, 2004).
10.25       Letter Agreement dated September 30, 2004, among Enterprise Products Partners L.P., GulfTerra Energy Partners, L.P. and Bart Heijermans (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners L.P.’s Form 8-K/A-2 filed on October 18, 2004).
10.27*       Form of EPE Unit L.P. Agreement of Limited Partnership.
10.28*       Enterprise Products Company 2005 EPE Long Term Incentive Plan.
10.29*       Form of Restricted Unit Grant under the Enterprise Products Company 2005 EPE Long Term Incentive Plan.
10.30*       Form of Contribution, Conveyance and Assumption Agreement among Enterprise GP Holdings L.P., EPE Holdings, LLC, Dan Duncan LLC, Duncan Family Interests, Inc. and other affiliates of EPCO.
10.31*       Form of $159.6 million note assumed by Enterprise GP Holdings L.P. and payable to EPCO, Inc.
10.32*       $370 million note owed by Enterprise Products GP, LLC to Dan Duncan LLC.
21.1*       List of Subsidiaries of Enterprise GP Holdings L.P.
23.1**       Consent of Deloitte & Touche LLP
23.2**       Consent of PricewaterhouseCoopers LLP
23.3**       Consent of Netherland, Sewell & Associates, Inc.
23.4*       Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1 and Exhibit 8.1)
24.1***       Powers of Attorney (included on signature page to this registration statement)
99.1**       Consent of Director nominee.
99.2**       Consent of Director nominee.

* To be filed by amendment.
** Filed herewith.
*** Previously filed.

 

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Index to Financial Statements

Item 17. Undertakings

 

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

 

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions described above in Item 14, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

 

The undersigned registrant hereby undertakes that:

 

(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

 

(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with EPE Holdings, LLC or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to EPE Holdings, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

 

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.

 

II-8


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Index to Financial Statements

SIGNATURES

 

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Amendment No. 2 to Registration Statement on Form S-1 to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on July 21, 2005.

 

ENTERPRISE GP HOLDINGS L.P.

By:

 

EPE Holdings, LLC,

its General Partner

By:

 

/ S /    M ICHAEL A. C REEL        


    Michael A. Creel
    President and Chief Executive Officer

 

Pursuant to the requirements of the Securities Act of 1933, as amended, this Amendment No. 2 to Registration Statement on Form S-1 has been signed below by the following persons in the capacities and on the dates indicated.

 

Signature


  

Title


 

Date


/ S /    M ICHAEL A. C REEL        


Michael A. Creel

  

President, Chief Executive Officer and Director (principal executive officer)

  July 21, 2005

/ S /    W. R ANDALL F OWLER *        


W. Randall Fowler

  

Senior Vice President and Chief Financial Officer (principal financial officer)

  July 21, 2005

/ S /    M ICHAEL J. K NESEK *        


Michael J. Knesek

  

Senior Vice President, Controller and Principal Accounting Officer (principal accounting officer)

  July 21, 2005

/ S /    D AN L. D UNCAN *        


Dan L. Duncan

  

Chairman of the Board and Director

  July 21, 2005

 

*By:   / S /    M ICHAEL A. C REEL        
   

Michael A. Creel

As Attorney-in-Fact

 

II-9


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Index to Financial Statements

EXHIBIT INDEX

 

Exhibit
Number


       

Description


1.1*       Form of Underwriting Agreement
3.1**       Certificate of Limited Partnership of Enterprise GP Holdings L.P.
3.2*       Form of Amended and Restated Agreement of Limited Partnership of Enterprise GP Holdings L.P. (included as Appendix A to the Prospectus)
3.3**       Certificate of Formation of EPE Holdings, LLC
3.4*       Form of Amended and Restated Limited Liability Company Agreement of EPE Holdings, LLC
4.1**       Specimen certificate representing units
4.2       Fourth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of October 1, 2004 (incorporated by reference to Exhibit 3.1 to Enterprise Products Partners L.P.’s Form 8-K filed October 6, 2004).
4.3       Second Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, among Duncan Family Interests, Inc., Dan Duncan LLC, and GulfTerra GP Holding Company dated September 30, 2004 (incorporated by reference to Exhibit 3.1 to Enterprise Products Partners L.P.’s Form 8-K filed September 30, 2004).
4.4       Application for Admission by Enterprise GP Holdings L.P. as a Substituted Member of Enterprise Products GP, LLC (incorporated by reference to Exhibit 3.1 to Enterprise Products Partners L.P.’s Form 8-K filed January 18, 2005).
4.5       Amended and Restated Agreement of Limited Partnership of Enterprise Products Operating L.P. dated as of July 31, 1998 (restated to include all agreements through December 10, 2003) (incorporated by reference to Exhibit 3.3 to Enterprise Products Partners L.P.’s Form 10-Q filed August 9, 2004).
4.6       Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed March 10, 2000).
4.7       First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners L.P.’s Registration Statement on Form S-4 filed January 28, 2003).
4.8       Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners L.P.’s Registration Statement on Form S-4 filed January 28, 2003).
4.9       Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Form 10-K filed March 31, 2003).
4.10       Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Enterprise Products Partners L.P.’s Form 10-K filed March 31, 2003).
4.11       Global Notes representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed January 25, 2001).


Table of Contents
Index to Financial Statements
Exhibit
Number


       

Description


4.12       Contribution Agreement dated September 17, 1999 (incorporated by reference to Exhibit “B” to Tejas Energy, LLC’s Schedule 13D filed September 27, 1999).
4.13       Registration Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “E” to Tejas Energy, LLC’s Schedule 13D filed September 27, 1999).
4.14       Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit “C” to Tejas Energy, LLC’s Schedule 13D filed September 27, 1999).
4.15       Amendment No. 1, dated September 12, 2003, to Unitholder Rights Agreement dated September 17, 1999 (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed September 15, 2003).
4.16       Agreement dated as of March 4, 2004 among Enterprise Products Partners L.P., Shell US Gas & Power LLC and Kayne Anderson MLP Investment Company (incorporated by reference to Exhibit 4.31 to Enterprise Products Partners L.P.’s Form S-3 Registration Statement filed March 4, 2004).
4.17       $750 Million Multi-Year Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, CitiBank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents, Mizuho Corporate Bank, Ltd., SunTrust Bank and The Bank of Nova Scotia, as Co-Documentation Agents, Wachovia Capital Markets, LLC, CitiGroup Global Markets Inc. and JPMorgan Chase Securities, Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed on August 30, 2004).
4.18       Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.1, above (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners L.P.’s Form 8-K filed on August 30, 2004).
4.19       $2.25 Billion 364-Day Revolving Credit Agreement dated as of August 25, 2004, among Enterprise Products Operating L.P., the Lenders party thereto, Wachovia Bank, National Association, as Administrative Agent, CitiCorp North America, Inc. and Lehman Commercial Paper Inc., as Co-Syndication Agents, JPMorgan Chase Bank, UBS Loan Finance LLC and Morgan Stanley Senior Funding, Inc., as Co-Documentation Agents, Wachovia Capital Markets, LLC, CitiGroup Global Markets Inc. and Lehman Brothers Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Form 8-K filed on August 30, 2004).
4.20       Guaranty Agreement dated as of August 25, 2004, by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent for the several lenders that are or become parties to the Credit Agreement included as Exhibit 4.3, above (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners L.P.’s Form 8-K filed on August 30, 2004).
4.21       Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).
4.22       First Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).


Table of Contents
Index to Financial Statements
Exhibit
Number


       

Description


4.23       Second Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).
4.24       Third Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).
4.25       Fourth Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).
4.26       Global Note representing $500 million principal amount of 4.000% Series B Senior Notes due 2007 with attached Guarantee (incorporated by reference to Exhibit 4.14 to Enterprise Products Partners L.P.’s Form S-3 Registration Statement filed on March 4, 2005).
4.27       Global Note representing $500 million principal amount of 4.625% Series B Senior Notes due 2009 with attached Guarantee (incorporated by reference to Exhibit 4.27 to Enterprise Products Partners L.P.’s Form 10-K filed on March 15, 2005).
4.28       Global Note representing $500 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Enterprise Products Partners L.P.’s Form S-3 Registration Statement filed on March 4, 2005).
4.29       Global Note representing $150 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Enterprise Products Partners L.P.’s Form S-3 Registration Statement filed on March 4, 2005).
4.30       Global Note representing $350 million principal amount of 6.650% Series A Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Enterprise Products Partners L.P.’s Form S-3 Registration Statement filed on March 4, 2005.)
4.31       Registration Rights Agreement dated as of October 4, 2004, among Enterprise Products Operating L.P., Enterprise Products Partners L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.17 to Enterprise Products Partners L.P.’s Form 8-K filed on October 6, 2004).
4.32       Fifth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Enterprise Products Partners L.P.’s Form 8-K filed on March 3, 2005).
4.33       Sixth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Form 8-K filed on March 3, 2005).
4.34       Rule 144A Global Note representing $250,000,000 principal amount of 5.00% Series A Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Enterprise Products Partners L.P.’s Form 8-K filed on March 3, 2005).
4.35       Rule 144A Note representing $250,000,000 principal amount of 5.75% Series A Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.5 to Enterprise Products Partners L.P.’s Form 8-K filed on March 3, 2005).


Table of Contents
Index to Financial Statements
Exhibit
Number


       

Description


4.36       Registration Rights Agreement dated as of March 2, 2005, among Enterprise Products Partners, L.P., Enterprise Products Operating L.P. and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.6 to Enterprise Products Partners L.P.’s Form 8-K filed on March 3, 2005).
4.37       Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Enterprise Products Partners L.P.’s Form 8-K filed on July 1, 2005).
5.1*       Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
8.1*       Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1*       Credit Facility
10.2*       Form of Third Amended and Restated Administrative Services Agreement
10.3       Purchase and Sale Agreement between Coral Energy, LLC and Enterprise Products Operating L.P. dated September 22, 2000 (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners L.P.’s Form 8-K filed September 26, 2000).
10.4       Purchase and Sale Agreement dated January 16, 2002 by and between Diamond-Koch, L.P. and Diamond-Koch III, L.P. and Enterprise Products Texas Operating L.P. (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners L.P.’s Form 8-K filed February 8, 2002.)
10.5       Purchase and Sale Agreement dated January 31, 2002 by and between D-K Diamond-Koch, L.L.C., Diamond-Koch, L.P. and Diamond-Koch III, L.P. as Sellers and Enterprise Products Operating L.P. as Buyer (incorporated by reference to Exhibit 10.2 to Enterprise Products Partners L.P.’s Form 8-K filed February 8, 2002).
10.6       Purchase Agreement by and between E-Birchtree, LLC and Enterprise Products Operating L.P. dated July 31, 2002 (incorporated by reference to Exhibit 2.2 to Enterprise Products Partners L.P.’s Form 8-K filed August 12, 2002).
10.7       Purchase Agreement by and between E-Birchtree, LLC and E-Cypress, LLC dated July 31, 2002 (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners L.P.’s Form 8-K filed August 12, 2002).
10.8       Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners L.P.’s Form 8-K filed December 15, 2003).
10.9       Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners L.P.’s Form 8-K filed September 7, 2004).
10.10       Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Enterprise Products Partners L.P.’s Form 8-K filed December 15, 2003).
10.11       Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to Enterprise Products Partners L.P.’s Form 8-K filed April 21, 2004).


Table of Contents
Index to Financial Statements
Exhibit
Number


       

Description


10.12       Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003 (incorporated by reference to Exhibit 2.3 to Enterprise Products Partners, L.P.’s Form 8-K filed December 15, 2003).
10.13       Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C. adopted by Enterprise Products GTM, LLC as of September 30, 2004 (incorporated by reference to Exhibit 2.11 to Enterprise Products Partners L.P.’s Registration Statement on Form S-4 filed December 27, 2004).
10.14       Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Enterprise Products Partners L.P.’s Form 8-K filed December 15, 2003).
10.15       Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998 (incorporated by reference to Exhibit 10.3 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1/A filed July 8, 1998).
10.16       Partnership Agreement among Sun BEF, Inc., Liquid Energy Fuels Corporation and Enterprise Products Company dated May 1, 1992 (incorporated by reference to Exhibit 10.5 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1 filed May 13, 1998).
10.17       Propylene Facility and Pipeline Agreement between Enterprise Petrochemical Company and Hercules Incorporated dated December 13, 1978 (incorporated by reference to Exhibit 10.9 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1 filed May 13, 1998).
10.18       Restated Operating Agreement for the Mont Belvieu Fractionation Facilities Chambers County, Texas among Enterprise Products Company, Texaco Producing Inc., El Paso Hydrocarbons Company and Champlin Petroleum Company dated July 17, 1985 (incorporated by reference to Exhibit 10.10 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1/A filed July 8,1998).
10.19       Amendment to Propylene Facility and Pipeline Agreement and Propylene Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1993 (incorporated by reference to Exhibit 10.12 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1/A filed July 8, 1998).
10.20       Amendment to Propylene Facility and Pipeline Agreement and Propylene Sales Agreement between HIMONT U.S.A., Inc. and Enterprise Products Company dated January 1, 1995 (incorporated by reference to Exhibit 10.13 to Enterprise Products Partners L.P.’s Registration Statement on Form S-1/A filed July 8, 1998).
10.21       Seventh Amendment to Conveyance of Gas Processing Rights, dated as of April 1, 2004 among Enterprise Gas Processing, LLC, Shell Oil Company, Shell Exploration & Production Company, Shell Offshore Inc., Shell Consolidated Energy Resources Inc., Shell Land & Energy Company, Shell Frontier Oil & Gas Inc. and Shell Gulf of Mexico Inc. (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners L.P.’s Form 8-K filed April 26, 2004).
10.22       Enterprise Products 1998 Long-Term Incentive Plan, amended and restated as of April 8, 2004 (incorporated by reference to Appendix B to Enterprise Products Partners L.P.’s Notice of Written Consent dated April 22, 2004, filed April 22, 2004).


Table of Contents
Index to Financial Statements
Exhibit
Number


       

Description


10.23       Form of Option Grant Award under 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Registration Statement on Form S-8 filed May 19, 2004).
10.24       Form of Restricted Unit Grant under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to Enterprise Products Partners L.P.’s Registration Statement on Form S-8 filed May 19, 2004).
10.25       Letter Agreement dated September 30, 2004, among Enterprise Products Partners L.P., GulfTerra Energy Partners, L.P. and Bart Heijermans (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners L.P.’s Form 8-K/A-2 filed on October 18, 2004).
10.27*       Form of EPE Unit L.P. Agreement of Limited Partnership.
10.28*       Enterprise Products Company 2005 EPE Long Term Incentive Plan.
10.29*       Form of Restricted Unit Grant under the Enterprise Products Company 2005 EPE Long Term Incentive Plan.
10.30*       Form of Contribution, Conveyance and Assumption Agreement among Enterprise GP Holdings L.P., EPE Holdings, LLC, Dan Duncan LLC, Duncan Family Interests, Inc. and other affiliates of EPCO.
10.31*       Form of $159.6 million note assumed by Enterprise GP Holdings L.P. and payable to EPCO, Inc.
10.32*       $370 million note owed by Enterprise Products GP, LLC to Dan Duncan LLC.
21.1*       List of Subsidiaries of Enterprise GP Holdings L.P.
23.1**       Consent of Deloitte & Touche LLP
23.2**       Consent of PricewaterhouseCoopers LLP
23.3**       Consent of Netherland, Sewell & Associates, Inc.
23.4*       Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1 and Exhibit 8.1)
24.1***       Powers of Attorney (included on signature page to this registration statement)
99.1**       Consent of Director nominee.
99.2**       Consent of Director nominee.

* To be filed by amendment.
** Filed herewith.
*** Previously filed.

EXHIBIT 3.1

 

CERTIFICATE OF LIMITED PARTNERSHIP

 

OF

 

ENTERPRISE GP HOLDINGS L.P.

 

This Certificate of Limited Partnership, dated April 18, 2005, has been duly executed and is filed pursuant to Section 17-201 of the Delaware Revised Uniform Limited Partnership Act (the “Act”) to form a limited partnership under the Act.

 

1. Name. The name of the limited partnership is “Enterprise GP Holdings L.P.”

 

2. Registered Office; Registered Agent. The address of the registered office required to be maintained by Section 17-104 of the Act is:

 

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801

 

The name and the address of the registered agent for service of process required to be maintained by Section 17-104 of the Act is:

 

The Corporation Trust Company

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801

 

3. General Partner. The name and the mailing address of the general partner is:

 

EPE Holdings, LLC

2727 North Loop West

Houston, Texas 77008

 

[Signature page follows]


IN WITNESS WHEREOF, the undersigned has duly executed this Certificate of Limited Partnership as of the date first written above.

 

EPE HOLDINGS, LLC
By:  

Dan Duncan LLC,

its sole member

   
    By:  

/s/ Richard H. Bachmann


Richard H. Bachmann

Executive Vice President, Secretary

and Manager

       
       
       

 

2

EXHIBIT 3.3

 

CERTIFICATE OF FORMATION

OF

EPE HOLDINGS, LLC

 

This Certificate of Formation, dated April 18, 2005, has been duly executed and is filed pursuant to Section 18-201 of the Delaware Limited Liability Company Act (the “Act”) to form a limited liability company (the “Company”) under the Act.

 

  1. Name. The name of the Company is “EPE Holdings, LLC”.

 

  2. Registered Office; Registered Agent. The address of the registered office required to be maintained by Section 18-104 of the Act is:

 

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801

 

The name and address of the registered agent for service of process required to be maintained by Section 18-104 of the Act are:

 

The Corporation Trust Company

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801

 

  3. Effective Time. The effective time of the formation of the Company contemplated hereby is immediately upon the filing of this Certificate of Formation with Secretary of State of Delaware.

 

IN WITNESS WHEREOF, the undersigned has duly executed this Certificate of Formation as of the date first written above.

 

/s/ Richard H. Bachmann


Richard H. Bachmann, Authorized Person

EXHIBIT 4.1

 

NUMBER

  

FORM OF SPECIMEN CERTIFICATE EVIDENCING UNITS

REPRESENTING LIMITED PARTNERSHIP INTERESTS IN

           UNITS

THIS CERTIFICATE IS TRANSFERABLE IN

NEW YORK, N.Y. AND RIDGEFIELD PARK, N.J.

   CUSIP 293716 10 6 SEE REVERSE FOR CERTAIN DEFINITIONS

 

ENTERPRISE GP HOLDINGS L.P.

A LIMITED PARTNERSHIP FORMED UNDER THE LAWS OF DELAWARE

 

In accordance with Section 4.1 of the Agreement of Limited Partnership of Enterprise GP Holdings L.P., as amended, supplemented or restated from time to time (the “Partnership Agreement”), Enterprise GP Holdings L.P., a Delaware limited partnership (the “Partnership”),

 

hereby certifies that

 

(the “Holder”) is the registered owner of

  Units        

 

representing limited partner interests in the Partnership (the “Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Units are set forth in, and this Certificate and the Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 2727 North Loop West, Suite 101, Houston, Texas 77008. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

 

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (iii) granted the powers of attorney provided for in the Partnership Agreement and (iv) made the waivers and given the consents and approvals contained in the Partnership Agreement.

 

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

 

Dated:

     Enterprise GP Holdings L.P.
       By:  

            EPE Holdings, LLC,

            its General Partner

       By:  

 


                                   President
       By:  

 


                                   Secretary

 

Countersigned and Registered by:

Mellon Investor Services LLC

                  as Transfer Agent and Registrar

 

By:

 

 


    Authorized Signature


[Reverse of Certificate]

 

ABBREVIATIONS

 

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

 

TEN COM

 

-

     

as tenants in common

as tenants by the entireties

as joint tenants with right of survivorship and not as

tenants in common

   UNIF GIFT MIN ACT -              Custodian                 

TEN ENT

 

-            

                                                  (Cust)                    (Minor)

JT TEN

 

-

        

 

                            under Uniform Gifts to Minors

                                                            Act                         
                                                                        (State)

 

Additional abbreviations, though not in the above list, may also be used.

 

ASSIGNMENT OF UNITS

IN

ENTERPRISE GP HOLDINGS L.P.

 

FOR VALUE RECEIVED,                                  hereby assigns, conveys, sells and transfers unto                                 

 

 


       

 


(Please insert Social Security or other identifying number of Assignee)         (Please print or typewrite name and address of Assignee)

 

             Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint                          as its attorney-in-fact with full power of substitution to transfer the same on the books of Enterprise GP Holdings L.P.

 

Date:                         

  NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.

 

SIGNATURE(S) MUST BE GUARANTEED

      ________________________________________

BY A MEMBER FIRM OF THE NATIONAL ASSOCIATION

      (Signature)

OF SECURITY DEALERS, INC. OR BY A

      ________________________________________

COMMERCIAL BANK OR TRUST COMPANY

      (Signature)

 

SIGNATURE(S) GUARANTEED

 

No transfer of the Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Units to be transferred is surrendered for registration or transfer and the Assignee completes and executes the form set forth below.


 


        Purchase Price including commission, if any

 

Type of Entity (check one):

 

[      ] Individual   [      ] Partnership  

[      ] Corporation

   
[      ] Trust   [      ] Other (specify)                                              

 

Nationality (check one):

 

[      ] U.S. Citizen, Resident or Domestic Entity

 

[      ] Foreign Corporation   [      ] Non-resident Alien

 

If the U.S. Citizen, Resident or Domestic Entity box is checked, the following certification must be completed.

 

Under Section 1445(e) of the Internal Revenue Code of 1986, as amended (the “Code”), the Partnership must withhold tax with respect to certain transfers of property if a holder of an interest in the Partnership is a foreign person.

 

To inform the Partnership that no withholding is required with respect to the undersigned interestholder’s interest in it, the undersigned hereby certifies the following (or, if applicable, certifies the following on behalf of the interestholder).

 

Complete Either A or B:

 

A. Individual Interestholder

 

1. I am not a non-resident alien for purposes of U.S. income taxation.

 

2. My U.S. taxpayer identification number (Social Security Number) is                                          .

 

3. My home address is                                                                                                                                                             .

 

4. My taxable year ends on December 31st.

 

B. Partnership, Corporation or Other Interestholder

 

1.                                                                                                                                                     is not a foreign

                                                         (Name of Interestholder)

corporation, foreign partnership, foreign trust or foreign estate (as those terms are defined in the Code and Treasury Regulations).

 

2. The interestholder’s U.S. employer identification number is                                          .

 

3. The interestholder’s office address and place of incorporation (if applicable) is                                                                 .

 

4. The interestholder’s taxable year ends on December 31st.

 

The interestholder agrees to notify the Partnership within sixty (60) days of the date the interestholder becomes a foreign person.

 

The interestholder understands that this certificate may be disclosed to the Internal Revenue Service by the Partnership and that any false statement contained herein could be punishable by fine, imprisonment or both.

 

Under penalties of perjury, I declare that I have examined this certification and to the best of my knowledge and belief it is true, correct and complete and, if applicable, I further declare that I have authority to sign this document on behalf of

 

 


Name of Interestholder

 

 


Signature and Date

 

 


Title (if applicable)

 

        Note: If the Assignee is a broker, dealer, bank, trust company, clearing corporation, other nominee holder or an agent of any of the foregoing, and is holding for the account of any other person, this application should be completed by an officer thereof or, in the case of a broker or dealer, by a registered representative who is a member of a registered national securities exchange or a member of the National Association of Securities Dealers, Inc., or, in the case of any other nominee holder, a person performing a similar function. If the Assignee is a broker, dealer, bank, trust company, clearing corporation, other nominee owner or an agent of any of the foregoing, the above certification as to any person for whom the Assignee will hold the Units shall be made to the best of the Assignee’s knowledge.

Exhibit 23.1

 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

We consent to the use in this Amendment No. 2 to Registration Statement No. 333-124320 on Form S-1 of (i) our report dated April 25, 2005, relating to the consolidated financial statements and financial statement schedule of Enterprise Products GP, LLC, (ii) our report dated June 15, 2005, with respect to the balance sheet of Enterprise GP Holdings L.P., and (iii) our report dated June 15, 2005, with respect to the balance sheet of EPE Holdings, LLC appearing in the Prospectus, which is part of this Registration Statement.

 

We also consent to the reference to us under the headings “Experts” in such Prospectus.

 

/s/ DELOITTE & TOUCHE LLP

 

Houston, Texas

July 21, 2005

Exhibit 23.2

 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

We hereby consent to the use in this Amendment No. 2 to Registration Statement on Form S-1 of Enterprise GP Holdings L.P. of (i) our report dated April 15, 2004 relating to the combined financial statements of El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P., (ii) our report dated March 12, 2004 relating to the consolidated financial statements of GulfTerra Energy Partners, L.P. and (iii) our report dated March 17, 2004 relating to the financial statements of Poseidon Oil Pipeline Company, L.L.C., all appearing in such Registration Statement. We also consent to the reference to us under the heading “Experts” in this Registration Statement.

 

/s/    PricewaterhouseCoopers LLP

   

Houston, Texas

July 21, 2005

Exhibit 23.3

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

 

We hereby consent to the inclusion in this Amendment No. 2 to the Registration Statement on Form S-1 of Enterprise GP Holdings L.P. of our reserve report dated as of December 31, 2001, which is included in such Registration Statement of Enterprise GP Holdings L.P. to be filed with the Securities and Exchange Commission on or about July 21, 2005. We also consent to the reference to us under the heading of “Experts” in such Registration Statement.

 

NETHERLAND, SEWELL & ASSOCIATES, INC.

By:   / S /    F REDERIC D. S EWELL        
    Frederic D. Sewell
    Chairman and Chief Executive Officer

 

Dallas, Texas

July 21, 2005

Exhibit 99.1

 

CONSENT OF NOMINEE FOR DIRECTOR

 

I hereby consent to being named as a person who will become a director of EPE Holdings, LLC, a Delaware limited liability company and the general partner of Enterprise GP Holdings L.P., a Delaware limited partnership (the “Partnership”), in the Registration Statement on Form S-1 (SEC File No. 333-124320) filed by the Partnership with the Securities and Exchange Commission (the “Registration Statement”), in the disclosure under the caption “Management” in the Registration Statement and to the filing of this consent as an exhibit to the Registration Statement.

 

Date: July 20, 2005

 

/s/ CHARLES E. McMAHEN


Charles E. McMahen

Exhibit 99.2

 

CONSENT OF NOMINEE FOR DIRECTOR

 

I hereby consent to being named as a person who will become a director of EPE Holdings, LLC, a Delaware limited liability company and the general partner of Enterprise GP Holdings L.P., a Delaware limited partnership (the “Partnership”), in the Registration Statement on Form S-1 (SEC File No. 333-124320) filed by the Partnership with the Securities and Exchange Commission (the “Registration Statement”), in the disclosure under the caption “Management” in the Registration Statement and to the filing of this consent as an exhibit to the Registration Statement.

 

Date: July 20, 2005

 

/s/ EDWIN E. SMITH


Edwin E. Smith