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The information in this preliminary prospectus supplement is not complete and may be changed. This preliminary prospectus supplement and the attached prospectus are not an offer to sell these securities, and we are not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

      Filed Pursuant to Rule 424(b)(3)

Registration No. 333-102778
333-102778-01
SUBJECT TO COMPLETION, DATED FEBRUARY 7, 2005

PRELIMINARY PROSPECTUS SUPPLEMENT

(To Prospectus Dated April 21, 2003)

(ENTERPRISE PRODUCTS PARTNERS L.P. LOGO)

10,000,000 Common Units

Enterprise Products Partners L.P.

$                  per common unit


    We are selling 10,000,000 common units representing limited partner interests in Enterprise Products Partners L.P. Our common units are listed on the New York Stock Exchange under the symbol “EPD.” The last reported sales price of our common units on the New York Stock Exchange on February 3, 2005 was $27.28 per common unit.

    Investing in our common units involves risk. See “Risk Factors” beginning on page S-19 of this prospectus supplement and on page 2 of the accompanying prospectus.

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

                 
Per Common Unit Total


Public Offering Price 
  $       $    
Underwriting Discount
  $       $    
Proceeds to Enterprise Products Partners (before expenses)
  $       $    

    We have granted the underwriters a 30-day option to purchase up to 1,500,000 additional common units to cover over-allotments.

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


Joint Book-Running Managers

 
UBS Investment Bank Citigroup


Goldman, Sachs & Co.

  Lehman Brothers
  Morgan Stanley
  Wachovia Securities
  A.G. Edwards
  Merrill Lynch & Co.
  Raymond James
  Sanders Morris Harris
  RBC Capital Markets
  KeyBanc Capital Markets

                         , 2005


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[ENTERPRISE PRODUCTS PARTNERS SYSTEM MAP, GULFTERRA SYSTEM MAP

AND COMBINED COMPANY SYSTEM MAP APPEAR HERE]


      This document is in two parts. The first part is this prospectus supplement, which describes the terms of this offering of common units. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to this offering of our common units. If the information varies between this prospectus supplement and the accompanying prospectus, you should rely on the information in this prospectus supplement.

      You should rely only on the information contained or incorporated by reference in this prospectus supplement or the accompanying prospectus. We have not authorized anyone to provide you with additional or different information. We are not making an offer to sell these securities in any state where the offer is not permitted. You should not assume that the information contained in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front of these documents or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since these dates.

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SUMMARY

      This summary highlights information from this prospectus supplement and the accompanying prospectus to help you understand our business and the common units. It does not contain all of the information that is important to you. You should read carefully the entire prospectus supplement, the accompanying prospectus, the documents incorporated by reference and the other documents to which we refer for a more complete understanding of this offering. You should read “Risk Factors” beginning on page S-19 of this prospectus supplement and on page 2 of the accompanying prospectus for more information about important risks that you should consider before making a decision to purchase common units in this offering.

      The information presented in this prospectus supplement assumes that the underwriters do not exercise their over-allotment option, unless otherwise indicated. All references in this prospectus supplement and the accompanying prospectus to number of units, earnings per unit or unit price give effect to our two-for-one unit split on May 15, 2002. “Our,” “we,” “us” and “Enterprise” as used in this prospectus supplement and the accompanying prospectus refer to Enterprise Products Partners L.P. and its wholly owned subsidiaries. “GulfTerra” as used in this prospectus supplement refers to GulfTerra Energy Partners, L.P. and its wholly owned subsidiaries, and “El Paso Corporation” as used in this prospectus supplement refers to El Paso Corporation and its wholly owned subsidiaries.

      Unless otherwise indicated, pro forma financial results presented in this prospectus supplement give effect to the completion of the merger-related and other transactions described in the unaudited pro forma consolidated financial statements included elsewhere in this prospectus supplement, and pro forma as adjusted financial results presented in this prospectus supplement also give effect to this offering. For a complete description of the adjustments we have made to arrive at the pro forma financial measures that we present in this prospectus supplement, please read the unaudited pro forma consolidated financial statements included elsewhere in this prospectus supplement.

Enterprise Products Partners L.P.

      We are a leading North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, natural gas liquids, or NGLs, and crude oil, and we are an industry leader in the development of midstream infrastructure in the deepwater trend of the Gulf of Mexico. We have the only integrated North American midstream network, which includes natural gas transportation, gathering, processing and storage; NGL fractionation (or separation), transportation, storage and import and export terminaling; and crude oil transportation and offshore production platform services. Our midstream network links producers of natural gas, NGLs and crude oil from the largest supply basins in the United States, Canada and the Gulf of Mexico with the largest consumers and international markets. 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. We provide integrated services to our customers and generate fee-based cash flow from multiple sources along our midstream energy “value chain.”

      We and our affiliates have completed several significant transactions related to our merger with GulfTerra, which closed on September 30, 2004, including:

  •  Our purchase of a 50% interest in GulfTerra’s general partner for $425 million on December 15, 2003;
 
  •  Prior to the merger, the contribution of El Paso Corporation’s remaining 50% interest in GulfTerra’s general partner to our general partner in exchange for a 9.9% interest in our general partner and $370 million in cash, and the subsequent contribution by our general partner of that 50% interest to us without consideration; and
 
  •  Our acquisition of certain midstream assets in South Texas related to GulfTerra’s business for approximately $156 million on September 30, 2004, but effective September 1, 2004.

Affiliates of our general partner acquired El Paso Corporation’s 9.9% interest in our general partner and approximately 13.5 million of our common units for approximately $425 million on January 14, 2005. El Paso

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Corporation and its affiliates no longer own any interest in us or our general partner as a result of this transaction.

      For the year ended December 31, 2003, we had revenues of $5.3 billion, operating income of $248.1 million and net income of $104.5 million. On a pro forma basis for the year ended December 31, 2003, we had revenues of $7.2 billion, operating income of $425.3 million and income from continuing operations of $112.5 million. For the nine months ended September 30, 2004, we had revenues of $5.5 billion, operating income of $247.7 million and net income of $152.9 million. On a pro forma basis for the nine months ended September 30, 2004, we had revenues of $6.8 billion, operating income of $424.3 million and income from continuing operations of $223.3 million. We recently announced unaudited results for the year ended December 31, 2004. For this period, we had revenues of $8.3 billion, operating income of $423.0 million and net income of $268.3 million. Please read “— Summary Historical and Pro Forma Financial and Operating Data” and our unaudited pro forma financial statements beginning on page F-1 of this prospectus supplement for a description of the transactions we have included in our pro forma presentation and “— Recent Developments — Fourth Quarter and Fiscal Year 2004 Unaudited Results” for additional summarized financial information.

Our Business Segments

     

      As a result of the GulfTerra merger and related transactions, we have reorganized our 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, which are generally organized and managed along our midstream energy value chain according to the type of services rendered and products produced and sold.

      Offshore Pipelines & Services. Our Offshore Pipelines & Services segment consists of (i) approximately 1,390 miles of natural gas pipelines strategically located to serve production activities in some of the most active drilling and development regions in the Gulf of Mexico, (ii) ownership interests in Gulf of Mexico offshore oil pipeline systems aggregating approximately 800 miles, which includes the recently constructed 390-mile Cameron Highway oil pipeline, and (iii) ownership interests in seven multi-purpose offshore hub platforms located in the Gulf of Mexico.

      Onshore Natural Gas Pipelines & Services. Our Onshore Natural Gas Pipelines & Services segment includes natural gas pipeline systems aggregating approximately 17,180 miles that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. Included in this segment are two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast natural gas markets. We also lease natural gas storage facilities located in Texas and Louisiana.

      NGL Pipelines & Services. Our NGL Pipelines & Services segment is comprised of (i) our natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 12,600 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 NGL import and export terminaling operations. We also lease two NGL storage facilities located in Texas.

      Petrochemical Services. Our Petrochemical Services segment includes our four propylene fractionation facilities, isomerization complex, and octane additive production facility. This segment also includes approximately 460 miles of various propylene pipeline systems and a 70-mile hi-purity isobutane pipeline.

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Our Business Strategy

      Our business strategy is to:

  •  capitalize on expected increases in natural gas, NGL 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.

Competitive Strengths

      We believe we have the following competitive strengths:

      Large-Scale, Integrated Network of Diversified Assets in Strategic Locations. We have the only integrated natural gas and NGL transportation, fractionation, processing, storage and import/export network in North America. Our operations are strategically located to serve the major supply basins for NGL-rich natural gas, the major NGL storage hubs in North America and international markets. We believe that our location in these markets provides better access to natural gas, NGL and petrochemical supply volumes, anticipated demand growth and business expansion opportunities. The GulfTerra merger has resulted in a more balanced, diversified company with access to new geographic areas, such as the San Juan and Permian Basins. We believe that the larger scope and scale of the combined company should result in greater operating strength and promote long-term unitholder value.

      Cash-Flow Stability Through Fee-Based Businesses and Balanced Asset Mix. Our cash flow is derived primarily from fee-based businesses which are not directly affected by volatility in energy commodity prices. We expect that our more diversified asset portfolio resulting from the GulfTerra merger should provide operating income from a broader range of sources than our operations on a stand-alone basis prior to the merger. GulfTerra’s historical operations generally benefitted from strong or average hydrocarbon prices, while our historical operations prior to the merger generally benefitted from stable or lower hydrocarbon prices. This relationship results in a natural hedge to natural gas prices that should provide greater cash flow stability to the combined company.

      Relationships with Major Oil, Natural Gas and Petrochemical Companies. We have long-term relationships with many of our suppliers and customers, and we believe that we will continue to benefit from these relationships. We jointly own facilities with many of our customers who either provide raw materials to or consume the end products from our facilities. These joint venture partners include major oil, natural gas and petrochemical companies, including BP, Burlington Resources, ChevronTexaco, Dow Chemical, Duke Energy Field Services, El Paso Corporation, ExxonMobil, Marathon and Shell.

      Strategic Platform for Continued Expansion. We believe that the GulfTerra merger has strengthened our leading business positions across the midstream energy value chain in some of the largest producing basins in North America. We have a significant portfolio of organic growth opportunities to construct new facilities or expand existing assets. To date, we have identified approximately $2 billion of organic growth projects over the next three years, including our recently announced Independence Trail and Independence Hub projects and the Constitution oil and natural gas pipeline projects in the deepwater areas of the Gulf of Mexico; the expansion of some of our key western NGL assets to support new production in the Rocky Mountain and San Juan regions; and enhancements to some of our existing facilities on the Texas Gulf Coast to serve our refining and petrochemical customers.

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      Lower Cost of Capital. We believe that our general partner’s maximum incentive distribution level of 25% (as compared to 50% for many publicly traded master limited partnerships) combined with our investment grade credit profile provides us with a lower cost of capital than many of our competitors, enabling us to compete more effectively in acquiring assets and expanding our asset base. We also believe that the larger scope and scale of the combined company should provide us with greater access to capital.

      Experienced Operator and Management Team. We have historically operated our largest natural gas processing and fractionation facilities and most of our pipelines. As the leading provider of NGL-related services, we have established a reputation in the industry as a reliable and cost-effective operator. Affiliates of Dan L. Duncan, our co-founder and the chairman of our general partner, own a 100% membership interest in our general partner. In addition, following this offering Mr. Duncan and his affiliates collectively will own an approximate 37.3% limited partner interest in us. The officers of our general partner average more than 25 years of industry experience.

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Ownership Structure and Management

      The following chart depicts our organizational structure and ownership after giving effect to this offering.

(GRAPH)

      The table below shows the current ownership of our common units and the ownership of our common units after giving effect to this offering.

                                   
Ownership After
Current Ownership the Offering


Percentage Percentage
Units Interest Units Interest




Public common units
    185,621,528       49.9%       195,621,528       51.1%  
EPCO common units
    142,592,215       38.3%       142,592,215       37.3%  
Shell common units
    36,572,122       9.8%       36,572,122       9.6%  
General partner interest
          2.0%             2.0%  
     
     
     
     
 
 
Total
    364,785,865       100.0%       374,785,865       100.0%  
     
     
     
     
 

      Information regarding our management is set forth under “Management” beginning on page S-34 of this prospectus supplement. Our principal executive offices are located at 2727 North Loop West, Houston, Texas 77008, and our telephone number is (713) 880-6500.

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The Offering

 
Common units offered 10,000,000 common units; or
 
11,500,000 common units if the underwriters exercise their over-allotment option in full.
 
Units outstanding after this offering 374,785,865 common units, or 376,285,865 common units if the underwriters exercise their over-allotment option in full.
 
Use of proceeds We will use the net proceeds from this offering, including our general partner’s proportionate capital contribution, to permanently reduce borrowings and commitments outstanding under our 364-day acquisition revolving credit facility. Any remaining proceeds will be used for general partnership purposes, which may include acquisitions or the temporary reduction of amounts borrowed under our multi-year revolving credit facility. The net proceeds from any exercise of the underwriters’ over-allotment option will be used in a similar manner.
 
Cash distributions Under our partnership agreement, we must distribute all of our cash on hand as of the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement.
 
On November 5, 2004, we paid a quarterly cash distribution for the third quarter of 2004 of $0.3950 per common unit, or $1.58 per unit on an annualized basis. On January 19, 2005, our general partner increased our quarterly cash distribution to $0.40 per common unit, or $1.60 per common unit on an annualized basis, beginning with cash distributions with respect to the fourth quarter of 2004. The distribution with respect to the fourth quarter of 2004 will be paid on February 14, 2005 to unitholders of record on January 31, 2005. The units purchased in this offering will not be entitled to receive this distribution.
 
When quarterly cash distributions exceed $0.253 per unit in any quarter, our general partner receives a higher percentage of the cash distributed in excess of that amount, in increasing percentages up to 25% if the quarterly cash distributions exceed $0.3085 per unit. For a description of our cash distribution policy, please read “Cash Distribution Policy” in the accompanying prospectus.
 
Estimated ratio of taxable income
to distributions
We estimate that if you own the common units you purchase in this offering through December 31, 2007, you will be allocated, on a cumulative basis, an amount of federal taxable income for the taxable years 2005 through 2007 that will be less than 10% of the cash distributed with respect to that period. Please read “Tax Consequences” in this prospectus supplement and the accompanying prospectus for the basis of this estimate.
 
New York Stock Exchange symbol EPD
 
Risk Factors There are risks associated with this offering and our business. You should consider carefully the risk factors beginning on page S-19 of this prospectus supplement and beginning on page 2 of the accompanying prospectus before making a decision to purchase common units in this offering.

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Recent Developments

Fourth Quarter and Fiscal Year 2004 Unaudited Results

      The following table sets forth our summarized results of operations and selected volumetric operating data for the periods indicated (dollars in millions, except per unit amounts):

                                   
For the Three
Months Ended For the Year Ended
December 31, December 31,


2003 2004 2003 2004




(Unaudited) (Unaudited)
Income Statement Data:
                               
Revenues
  $ 1,419.4     $ 2,859.6     $ 5,346.4     $ 8,318.1  
Costs and expenses
    1,356.0       2,694.9       5,084.3       7,947.9  
Equity in income (loss) of unconsolidated affiliates
    2.7       10.6       (14.0 )     52.8  
     
     
     
     
 
 
Operating income
    66.1       175.3       248.1       423.0  
Other income (expense)
    (31.8 )     (57.6 )     (134.4 )     (153.6 )
Provision for taxes
    (0.6 )     (1.0 )     (5.3 )     (3.8 )
Minority interest
    0.5       (1.3 )     (3.9 )     (8.1 )
Cumulative effect of changes in accounting principle
                      10.8  
     
     
     
     
 
 
Net income
  $ 34.2     $ 115.4     $ 104.5     $ 268.3  
     
     
     
     
 
Fully diluted earnings per unit
  $ 0.13     $ 0.28     $ 0.41     $ 0.87  
     
     
     
     
 
EBITDA
  $ 99.9     $ 275.6     $ 366.4     $ 623.1  
     
     
     
     
 
Gross operating margin by segment:
                               
 
Offshore Pipelines & Services
  $ 0.1     $ 33.9     $ 5.6     $ 36.5  
 
Onshore Natural Gas Pipelines & Services
    4.1       72.0       18.3       91.0  
 
NGL Pipelines & Services
    80.1       142.5       310.6       374.2  
 
Petrochemical Services
    24.7       30.8       75.9       121.5  
 
Other, non-segment results(1)
                      32.0  
     
     
     
     
 
Total gross operating margin
  $ 109.0     $ 279.2     $ 410.4     $ 655.2  
     
     
     
     
 
Selected Volumetric Operating Data:(2)
                               
Offshore Pipelines & Services, net:
                               
 
Natural gas transportation volumes in billion British thermal units (BBtus) per day(3)
    378       1,828       433       2,081  
 
Crude oil transportation volumes (MBbls/d)
          138             138  
 
Platform gas treating (Mdth/d)
          306             306  
 
Platform oil treating (MBbls/d)
          14             14  
Onshore Natural Gas Pipelines & Services, net:
                               
 
Natural gas transportation volumes (BBtu/d)
    627       5,621       600       5,638  
NGL Pipelines & Services, net:
                               
 
NGL transportation volumes (MBbls/d)
    1,281       1,390       1,275       1,411  
 
NGL fractionation volumes (MBbls/d)
    241       304       227       307  
 
Equity NGL production (MBbls/d)
    44       128       43       129  
 
Fee-based natural gas processing (MMcf/d)
    324       1,844       194       1,692  
Petrochemical Services, net:
                               
 
Butane isomerization volumes (MBbls/d)
    70       85       77       76  
 
Propylene fractionation volumes (MBbls/d)
    56       54       57       57  
 
Octane additive production volumes (MBbls/d)
    7       13       4       10  
 
Petrochemical transportation volumes (MBbls/d)
    75       69       68       71  
Total, net:
                               
 
NGL, crude oil and petrochemical transportation volumes (MBbls/d)
    1,356       1,597       1,343       1,620  
 
Natural gas transportation volumes (BBtu/d)
    1,005       7,449       1033       7,719  
 
Equivalent transportation volumes (MBbls/d)(4)
    1,621       3,557       1,615       3,651  


(1)  The Other, non-segment category is presented for financial reporting purposes to show the historical equity earnings we received from GulfTerra’s general partner. Our investment in GulfTerra’s general partner was accounted for using the equity method until the GulfTerra merger and related transactions were completed on September 30, 2004. 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 us to allocate the equity income we received during the periods presented to each of our new segments. Therefore, we have segregated earnings from GulfTerra’s general partner apart from our other segments to aid in comparability between the periods presented and future periods.
 
(2)  Throughput rates reflect the periods that we owned the underlying businesses.
 
(3)  Excludes fourth quarter of 2004 volumes for Starfish, which is being disposed of.
 
(4)  Reflects equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent to one barrel of NGLs.

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     Please read “— Non-GAAP Financial Measures” and “— Non-GAAP Reconciliations” on pages S-15 through S-18 for an explanation of our gross operating margin and a reconciliation of gross operating margin to operating income, which is the financial measure calculated and presented in accordance with GAAP that is the most directly comparable to gross operating margin, and for an explanation of EBITDA and a reconciliation of EBITDA to net income and operating activities cash flows, which are the financial measures calculated and presented in accordance with GAAP that are the most directly comparable to EBITDA.

     Overview of Fourth Quarter and Fiscal Year 2004 Unaudited Results

      We reported quarterly net income of $115.4 million, or $0.28 per unit on a fully diluted basis, for the fourth quarter of 2004 compared to $34.2 million, or $0.13 per unit, for the fourth quarter of 2003. For the fiscal year of 2004, we earned net income of $268.3 million, or $0.87 per unit, compared to $104.5 million, or $0.41 per unit, in 2003.

      Revenue for the fourth quarter of 2004 increased by 101%, to approximately $2.9 billion compared to $1.4 billion for the fourth quarter of 2003. Operating income for the fourth quarter of 2004 increased by 165% to $175.3 million compared to $66.1 million for the fourth quarter of 2003. Gross operating margin increased by 156% to $279.2 million for the fourth quarter of 2004 from $109.0 million for the same quarter in 2003. Earnings before interest, taxes, depreciation and amortization, or EBITDA, increased by 176% to $275.6 million for the fourth quarter of 2004 from $99.9 million for the fourth quarter of 2003.

     Review of Segment Performance

      NGL Pipelines & Services. The NGL Pipelines & Services segment includes our NGL pipelines, storage facilities and fractionators and our natural gas processing plants and related NGL marketing activities. Gross operating margin for this segment increased by 78%, or $62.4 million, in the fourth quarter of 2004 to $142.5 million from $80.1 million in the same quarter in 2003.

      Our natural gas processing and related businesses accounted for $75.1 million of gross operating margin for this segment in the fourth quarter of 2004 compared to $7.6 million in the fourth quarter of 2003. This increase was due to the contributions from the GulfTerra assets and nine processing plants acquired from El Paso Corporation in the third quarter of 2004 as well as improved performance from our legacy processing plants and NGL marketing business. The processing business benefited from favorable processing economics due to the continued strong demand for NGLs by the petrochemical and motor gasoline industries as a result of improvements in the U.S. and global economies.

      Gross operating margin from the NGL pipelines and storage business was $52.0 million during the fourth quarter of 2004 versus $61.0 million in the fourth quarter of 2003. The Mid-America and Seminole pipelines accounted for $44.7 million of the gross operating margin for our NGL pipelines and storage business during the fourth quarter of 2004. This is a 24%, or $8.5 million, increase from the $36.2 million these pipelines earned during the same quarter of 2003. This increase was more than offset by a decrease in gross operating margin from export terminal services, reduced demand for certain Louisiana NGL pipelines, in part due to lower volumes resulting from the effects of Hurricane Ivan, and pipeline integrity expenses.

      Total transportation volumes for the NGL pipeline business averaged 1,390 thousand barrels, or MBbls, per day for the fourth quarter of 2004 compared to 1,281 MBbls per day in the fourth quarter of 2003. Transportation volumes for the Mid-America and Seminole pipelines increased by 15%, or 120 MBbls per day, to 908 MBbls per day in the fourth quarter of 2004 from 788 MBbls per day in the same period of 2003.

      Our NGL fractionation business earned gross operating margin of $15.3 million for the fourth quarter of 2004 compared to $11.5 million in the fourth quarter of 2003. NGL fractionation volumes for the fourth quarter of 2004 averaged 304 MBbls per day versus 241 MBbls per day in the fourth quarter of 2003.

      Onshore Natural Gas Pipelines & Services. The Onshore Natural Gas Pipelines & Services segment includes our onshore natural gas pipelines and natural gas storage businesses. Gross operating margin for this segment for the fourth quarter of 2004 was $72.0 million compared to $4.1 million in the fourth quarter of 2003.

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      Onshore natural gas pipelines generated $64.8 million of gross operating margin in the fourth quarter of 2004 versus $4.1 million in the fourth quarter of 2003. Onshore transportation volumes were 5.6 trillion British thermal units, or Tbtus, per day compared to 0.6 Tbtus per day in the fourth quarter of 2003. Natural gas storage services accounted for $7.2 million of gross operating margin in the fourth quarter of 2004. This combined $67.9 million increase for the segment was due to the contribution of the GulfTerra assets and increased margin and volume on the Acadian system.

      Offshore Pipelines & Services. The Offshore Pipelines & Services segment includes our offshore natural gas and crude oil pipelines and platforms. Gross operating margin for this segment for the fourth quarter of 2004 was $33.9 million compared to $0.1 million in the fourth quarter of 2003.

      Offshore natural gas pipelines recorded gross operating margin of $14.4 million on average throughput of 1.8 Tbtus per day in the fourth quarter of 2004 versus $0.1 million and 0.4 Tbtus per day, respectively, for the same quarter in 2003. Gross operating margin for our offshore platform services and production business was $13.6 million for the fourth quarter of 2004. Our offshore oil pipelines business recorded gross operating margin of $5.8 million in the fourth quarter of 2004 on net volumes of 138 MBbls per day. The increase for this segment was primarily attributable to the contribution from the GulfTerra assets.

      Petrochemical Services. The Petrochemical Services segment includes the partnership’s butane isomerization, propylene fractionation and octane enhancement businesses including related pipeline facilities. Gross operating margin for this segment during the fourth quarter of 2004 increased by 25%, or $6.1 million, to $30.8 million from $24.7 million in the same quarter of 2003. Each of the three businesses in this segment reported an increase in gross operating margin.

Other Recent Developments

 
      Receipt of First Deliveries From Holstein and Mad Dog Fields in Deepwater Gulf of Mexico

      In January 2005, we began receiving first deliveries of crude oil and natural gas from the Holstein and Mad Dog fields located in the Southern Green Canyon area of the deepwater Gulf of Mexico.

      Initial oil production of approximately 35,000 barrels, or Bbls, per day from three deepwater wells has commenced flowing into our recently completed and jointly owned Cameron Highway Oil Pipeline System, a 390-mile 24-inch to 30-inch pipeline, which has the capacity to deliver up to 500,000 Bbls per day of crude oil from developments in the Gulf of Mexico to the major refining markets along the Texas Gulf Coast.

      Cameron Highway is supported by life of lease dedications with BP, BHP Billiton and Unocal 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 under a term agreement to move its 50% share of production from the Holstein field.

      Initial natural gas production of approximately 100 million cubic feet, or MMcf, per day from the Holstein field has commenced flowing into our 25.7% owned Manta Ray Offshore Gathering System and Nautilus Gas Pipeline. The 101-mile, 30-inch Nautilus Gas Pipeline system terminates onshore in St. Mary’s Parish Louisiana, where the natural gas is processed at our Neptune natural gas processing plant. The gathering, transportation and processing agreements with BP, BHP Billiton and Unocal include life of lease dedications for the Holstein, Mad Dog and Atlantis developments while Shell’s natural gas production from Holstein is gathered and transported under a life of lease dedication and processed under an existing 20-year contract.

      The Holstein field began producing oil and natural gas in December 2004. First production from the Mad Dog field commenced in January 2005. The total combined design capacity of the Holstein, Mad Dog and Atlantis platforms is 400,000 Bbls per day and 340 MMcf per day, and the design capacity of the Constitution platform is 70,000 Bbls per day.

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      Acquisition of Natural Gas Gathering and Processing Companies from El Paso

      In January 2005, we acquired two subsidiaries of El Paso Corporation which own and operate a natural gas gathering system and natural gas cryogenic processing plant located in East Texas for $74.5 million. We received required regulatory approvals prior to closing. The companies we acquired own an 80% equity interest in three gathering systems located in Polk County, Texas, which represent a combined 89 miles of 2-inch to 12-inch pipeline system and a 75% equity interest in the Indian Springs gas processing facility located in Polk County, Texas. The Indian Springs processing plant has capacity to process up to 120 MMcf per day of natural gas. In addition, there is an idle 20 MMcf per day train available for restart to support an increase in gas volumes. The gas processed at the Indian Springs plant is sourced from the Polk County gas gathering systems, as well as our nearby Big Thicket gathering system. Additionally, the Indian Springs plant produces over 6,000 Bbls per day of NGLs that are currently fractionated at a facility in Mont Belvieu.

 
Divestiture of Ownership Interest Related to Stingray Natural Gas Pipeline

      In connection with the GulfTerra merger, we are required under a consent decree to sell our 50% interest in an entity 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. We expect this sale to close during the first quarter of 2005. The sale requires Federal Trade Commission approval under the terms of the consent decree relating to the GulfTerra merger and is subject to other customary closing conditions.

 
      Receipt of New Production Into Poseidon Oil Pipeline System

      In January 2005, the Poseidon Oil Pipeline began receiving crude oil from the Front Runner and Tarantula fields located in the central Gulf of Mexico. We own a 36% interest in Poseidon Oil Pipeline Company, L.L.C., which owns and operates the Poseidon Oil Pipeline System that extends from the central Gulf of Mexico onshore into Southern Louisiana.

      Poseidon constructed, owns and operates the Front Runner oil pipeline, a new 36-mile, 14-inch pipeline that connects the Front Runner field with Poseidon’s main pipeline at Ship Shoal Block 332. The Front Runner oil pipeline has the capacity to transport 65,000 Bbls of crude oil per day and can be expanded to transport up to 125,000 Bbls of crude oil per day.

      The Front Runner field is located in 3,100 feet of water in the Green Canyon Blocks 338 and 339 in the Central Gulf of Mexico. The field is currently producing in excess of 10,000 Bbls per day of crude oil from the first of eight wells, and is expected to produce up to 60,000 Bbls per day of crude oil. The producers in the field have dedicated a total of 13 contiguous blocks in this area to Poseidon.

      The Tarantula field is located in 480 feet of water in South Timbalier Block 308 and is connected to the Poseidon system by a new four-mile gathering pipeline owned by us. The field development consists of a fixed platform designed to initially handle 30,000 Bbls of crude oil per day and production from four wells.

 
      Acquisition of Additional Interest in Louisiana NGL Facilities

      In December 2004, we purchased an additional 16.7% ownership interest in K/ D/ S Promix, L.L.C., or Promix, for $27.5 million in cash from Koch Hydrocarbon Southeast Inc. As a result of this purchase, our ownership interest in Promix increased to 50%.

      Promix owns a fractionator located in Napoleonville, Louisiana, which has the capacity to fractionate up to 145,000 Bbls per day of NGLs from natural gas processing plants on the Louisiana, Mississippi and Alabama Gulf Coast. It also owns an NGL pipeline system that gathers mixed NGLs from natural gas processing plants in Louisiana, five NGL salt dome storage wells and a barge loading facility on the Gulf Coast of Louisiana. We are the operator of the Promix facilities. Promix provides a link between natural gas

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processing plants on the Gulf Coast that remove NGLs from natural gas produced from deepwater developments and NGL consumers in Louisiana and, through our pipelines, markets in Texas.
 
      Agreement with Atwater Valley Producers Group for Deepwater Platform and Gas Pipeline

      In November 2004, we entered into an agreement with the Atwater Valley Producers Group for the dedication, processing and gathering of natural gas and condensate production from six natural gas fields in the Atwater Valley, DeSoto Canyon and Lloyd Ridge areas of the deepwater Gulf of Mexico. We 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 of gas per day. The platform, which is estimated to cost approximately $385 million, will be operated by Anadarko Petroleum Corp., and is designed to process production from the six anchor fields and has excess payload capacity to tie-back up to 10 additional fields. In December 2004, we entered into an agreement with Cal Dive International Inc., or Cal Dive, to sell them a 20% interest in one of our affiliates that owns the Independence Hub platform. Under the terms of the agreement, we will have access to Cal Dive’s fleet of vessels, which will assist us in the construction of the Independence Hub and the related export pipeline.

      Independence Hub will be located on Mississippi Canyon block 920, in a water depth of 8,000 feet. This location was selected for the permanently anchored host facility 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 development will include dedicated anchor fields in addition to future discoveries on surrounding undeveloped blocks. Additionally, we will own, install and operate 140 miles of 24-inch pipeline, with a capacity of approximately 850 MMcf of gas per day, named Independence Trail. The pipeline, which is estimated to cost approximately $280 million, will redeliver the production from Independence Hub into the Tennessee Gas Pipeline.

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Summary Historical and Pro Forma Financial and Operating Data

      The following tables set forth, for the periods and at the dates indicated, summary historical and pro forma financial and operating data for Enterprise. The summary historical income statement and balance sheet data for the three years in the period ended December 31, 2003 are derived from and should be read in conjunction with the audited financial statements of Enterprise, GulfTerra and the South Texas midstream assets that are incorporated by reference into this prospectus supplement. The summary historical income statement data for the nine-month periods ended September 30, 2003 and 2004 and balance sheet data at September 30, 2004 are derived from and should be read in conjunction with the unaudited financial statements of Enterprise that are incorporated by reference into this prospectus supplement.

      Our summary unaudited pro forma financial and operating data gives effect to the following transactions:

  •  The completion of our merger with GulfTerra and the related transactions on September 30, 2004 (including our purchase of certain midstream assets located in South Texas, effective as of September 1, 2004).
 
  •  The issuance by our operating partnership of $2 billion of senior unsecured notes on October 4, 2004, and the application of the net proceeds therefrom to reduce debt amounts outstanding under our 364-day acquisition revolving credit facility that was used to fund a portion of the purchase price at the closing of the GulfTerra merger and related transactions on September 30, 2004.
 
  •  The completion on October 5, 2004 of our 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 in cash borrowed under our 364-day acquisition revolving credit facility, which was placed in escrow on September 30, 2004.
 
  •  Our public offerings of common units in both May 2004 and August 2004, each consisting of 17,250,000 common units, and our issuance of a total of 5,183,591 common units in connection with our distribution reinvestment plan, or DRIP, during the first eleven months of 2004 (2,199,350 common units were issued in connection with the DRIP in November 2004).
 
  •  The conversion of the remaining outstanding 80 Series F2 convertible units, which were originally issued by GulfTerra, into an aggregate of 1,950,317 of our common units in October and November 2004.

      Our summary unaudited pro forma as adjusted financial and operating data also gives effect to the sale of 10,000,000 of our common units to the public in this offering at an assumed offering price of $27.28 per unit and the application of the net proceeds as described in “Use of Proceeds.” Estimated net proceeds from this offering, including our general partner’s proportionate net capital contribution of $5.4 million, are $266.5 million after deducting applicable underwriting discounts, commissions and offering expenses of $11.9 million.

      The unaudited pro forma financial and operating data for the year ended December 31, 2003 and for the nine months ended September 30, 2004 assume the pro forma transactions described above and this offering all occurred on January 1, 2003. The unaudited pro forma condensed consolidated balance sheet data shows the financial effects of the pro forma transactions described above and this offering as if they had occurred on September 30, 2004 (to the extent these transactions are not already recorded in our historical balance sheet).

      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. In supplemental sections titled “— Non-GAAP Financial Measures” and “— Non-GAAP Reconciliations,” we have provided the necessary explanations and reconciliations for Enterprise’s non-GAAP financial measures.

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Summary Historical and Pro Forma Financial and Operating Data

                                               
Consolidated Historical

For Year Ended
December 31, 2003
For Year Ended December 31,

Pro Forma
2001 2002 2003 Pro Forma as Adjusted





(Unaudited)
(Dollars in millions, except per unit amounts)
Income Statement Data:
                                       
 
Revenues
  $ 3,154.4     $ 3,584.8     $ 5,346.4     $ 7,153.0     $ 7,153.0  
 
Costs and expenses:
                                       
   
Operating costs and expenses
    2,862.6       3,382.8       5,046.8       6,633.1       6,633.1  
   
Selling, general and administrative
    30.3       42.9       37.5       92.0       92.0  
     
     
     
     
     
 
     
Total costs and expenses
    2,892.9       3,425.7       5,084.3       6,725.1       6,725.1  
     
     
     
     
     
 
 
Equity in income (loss) of unconsolidated affiliates
    25.3       35.2       (14.0 )     (2.6 )     (2.6 )
     
     
     
     
     
 
 
Operating income
    286.8       194.3       248.1       425.3       425.3  
     
     
     
     
     
 
 
Other income (expense):
                                       
   
Interest expense
    (52.4 )     (101.6 )     (140.8 )     (321.1 )     (312.0 )
   
Other, net
    10.3       7.3       6.4       8.4       8.4  
     
     
     
     
     
 
     
Total other income (expense)
    (42.1 )     (94.3 )     (134.4 )     (312.7 )     (303.6 )
     
     
     
     
     
 
 
Income before provision for income taxes and minority interest
    244.7       100.0       113.7       112.6       121.7  
 
Provision for income taxes
          (1.6 )     (5.3 )     (5.3 )     (5.3 )
     
     
     
     
     
 
 
Income before minority interest
    244.7       98.4       108.4       107.3       116.4  
 
Minority interest
    (2.5 )     (2.9 )     (3.9 )     (3.9 )     (3.9 )
     
     
     
     
     
 
 
Income from continuing operations
  $ 242.2     $ 95.5     $ 104.5     $ 103.4     $ 112.5  
                             
     
 
 
Cumulative effect of change in accounting principle
                                 
     
     
     
                 
 
Net income
  $ 242.2     $ 95.5     $ 104.5                  
     
     
     
                 
Basic earnings per unit (net of general partner interest):
                                       
 
Income from continuing operations per unit
  $ 1.70     $ 0.55     $ 0.42     $ 0.19     $ 0.21  
     
     
     
     
     
 
Diluted earnings per unit (net of general partner interest):
                                       
 
Income from continuing operations per unit
  $ 1.39     $ 0.48     $ 0.41     $ 0.19     $ 0.20  
     
     
     
     
     
 
Distributions to limited partners:
                                       
 
Per common unit
  $ 1.19     $ 1.36     $ 1.47                  
     
     
     
                 
Balance sheet data:
                                       
 
Total assets
  $ 2,424.7     $ 4,230.3     $ 4,802.8                  
 
Total debt
    855.3       2,246.5       2,139.5                  
 
Total partners’ equity
    1,146.9       1,200.9       1,705.9                  
Other financial data:
                                       
 
Cash provided by operating activities
  $ 277.6     $ 326.8     $ 419.6                  
 
Cash flows used in investing activities
    491.2       1,708.3       657.0                  
 
Cash provided by financing activities
    285.3       1,263.3       254.0                  
 
Distributions received from unconsolidated affiliates
    45.1       57.7       31.9                  
 
Gross operating margin
    375.9       332.3       410.4     $ 887.3     $ 887.3  
 
EBITDA
    345.8       284.8       366.4       809.5       809.5  
 
Commodity hedging income (losses)
    101.3       (51.3 )     (0.6 )                

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Summary Historical and Pro Forma Financial and Operating Data (Continued)

                                       
Consolidated
Historical

For Nine Months For Nine Months Ended
Ended September 30, 2004
September 30,

Pro Forma
2003 2004 Pro Forma as Adjusted




(Unaudited)
(Dollars in millions, except per unit amounts)
Income Statement Data:
                               
 
Revenues
  $ 3,927.0     $ 5,458.5     $ 6,752.4     $ 6,752.4  
 
Costs and expenses:
                               
   
Operating costs and expenses
    3,699.5       5,226.4       6,272.8       6,272.8  
   
Selling, general and administrative
    28.9       26.6       73.1       73.1  
     
     
     
     
 
     
Total costs and expenses
    3,728.4       5,253.0       6,345.9       6,345.9  
     
     
     
     
 
 
Equity in income (loss) of unconsolidated affiliates
    (16.6 )     42.2       17.8       17.8  
     
     
     
     
 
 
Operating income
    182.0       247.7       424.3       424.3  
     
     
     
     
 
 
Other income (expense):
                               
   
Interest expense
    (107.7 )     (96.9 )     (202.5 )     (195.7 )
   
Other, net
    5.1       0.9       2.5       2.5  
     
     
     
     
 
     
Total other income (expense)
    (102.6 )     (96.0 )     (200.0 )     (193.2 )
     
     
     
     
 
 
Income before provision for income taxes, minority interest and change in accounting principle
    79.4       151.7       224.3       231.1  
 
Provision for income taxes
    (4.6 )     (2.7 )     (2.7 )     (2.7 )
     
     
     
     
 
 
Income before minority interest and changes in accounting principles
    74.8       149.0       221.6       228.4  
 
Minority interest
    (4.4 )     (6.9 )     (5.1 )     (5.1 )
     
     
     
     
 
 
Income from continuing operations
    70.4       142.1     $ 216.5     $ 223.3  
                     
     
 
 
Cumulative effect of change in accounting principle
          10.8                  
     
     
                 
 
Net income
  $ 70.4     $ 152.9                  
     
     
                 
Basic earnings per unit (net of general partner interest):
                               
 
Income from continuing operations per unit
  $ 0.29     $ 0.52     $ 0.50     $ 0.50  
     
     
     
     
 
Diluted earnings per unit (net of general partner interest):
                               
 
Income from continuing operations per unit
  $ 0.28     $ 0.52     $ 0.50     $ 0.50  
     
     
     
     
 
Distributions to limited partners:
                               
 
Per common unit
  $ 1.10     $ 1.14                  
Balance sheet data:
                               
 
Total assets
  $ 4,281.7     $ 12,183.4             $ 11,223.9  
 
Total debt
    1,889.6       5,579.4               4,265.5  
 
Total partners’ equity
    1,605.3       5,279.6               5,635.0  
Other financial data:
                               
 
Cash provided by operating activities
  $ 222.7     $ 33.0                  
 
Cash used in investing activities
    153.5       734.7                  
 
Cash provided by (used in) financing activities
    (42.8 )     817.9                  
 
Distributions received from unconsolidated affiliates
    25.7       54.6                  
 
Gross operating margin
    301.4       376.0     $ 791.9     $ 791.9  
 
EBITDA
    266.5       347.2       709.2       709.2  
                                             
Enterprise Consolidated Historical

For Nine
For Year Ended Months Ended
December 31, September 30,


2001 2002 2003 2003 2004





Selected Volumetric Operating Data:
                                       
 
Offshore pipelines & services, net volumes in billion British thermal units (BBtus) per day
                                       
   
Natural gas transportation volumes
    566       500       433       451       423  
 
Onshore natural gas pipelines & services, net volumes in BBtus/d
                                       
   
Natural gas transportation volumes
    783       701       599       590       650  
 
NGL pipelines & services, net volumes as shown
                                       
   
NGL transportation volumes (thousand barrels (MBbls) per day, net)
    420       1,306       1,275       1,273       1,358  
   
NGL fractionation volumes (MBbls/d, net)
    204       235       227       223       235  
   
Equity NGL production (MBbls/d, net)
    63       73       43       42       47  
   
Fee-based natural gas processing (MMcf/d, net)
    *       *       194       150       944  
 
Petrochemical services, net volumes in MBbls/d
                                       
   
Butane isomerization volumes
    80       84       77       80       73  
   
Propylene fractionation volumes
    31       55       57       57       58  
   
Octane additive production volumes
    5       5       4       4       9  
   
Petrochemical transportation volumes
    33       46       68       63       73  


* Fee-based natural gas processing volumes prior to 2003 were negligible.

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Non-GAAP Financial Measures

      We include in this prospectus supplement 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 define gross operating margin as operating income before: (1) depreciation and amortization expense; (2) operating lease expenses for which we do not have the cash payment obligation; (3) gains and losses on the sale of assets; and (4) selling, general and administrative expenses. We view gross operating margin as 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 our 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. The GAAP measure most directly comparable to gross operating margin is operating income.

EBITDA

      EBITDA is defined as net income (income from continuing operations with regards to pro forma information) plus interest expense, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental financial measure by our management and by external users of financial statements such as investors, commercial banks, research analysts and ratings agencies, to assess:

  •  the financial performance of our assets without regard to financing methods, capital structures or historical costs basis;
 
  •  the ability of our assets to generate cash sufficient to pay interest cost and support its indebtedness;
 
  •  our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing and capital structure; and
 
  •  the viability of projects and the overall rates of return on alternative investment opportunities.

      EBITDA should not be considered an alternative to net income or income from continuing operations, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. This non-GAAP financial measure is not intended to represent GAAP-based cash flows. We have reconciled our historical and pro forma EBITDA amounts to our consolidated net income (income from continuing operations with regards to pro forma information) and historical EBITDA amounts further to operating activities cash flows.

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Non-GAAP Reconciliations

      The following table presents a reconciliation of our non-GAAP financial measures of gross operating margin to the GAAP financial measure of operating income and a reconciliation of the non-GAAP financial measure of EBITDA to the GAAP financial measures of net income (income from continuing operations with regards to pro forma information) and of operating activities cash flows, on a historical and pro forma as adjusted basis, as applicable, for each of the periods indicated:

                                             
Consolidated Historical

For Year Ended
December 31, 2003
For Year Ended December 31,

Pro Forma
2001 2002 2003 Pro Forma as Adjusted





(Unaudited)
(Dollars in millions)
Reconciliation of Non-GAAP “Gross operating margin” to GAAP “Operating income”
                                       
Operating income
  $ 286.8     $ 194.3     $ 248.1     $ 425.3     $ 425.3  
 
Adjustments to reconcile Operating income to Gross operating margin:
                                       
   
Depreciation and amortization in operating costs and expenses
    48.8       86.0       115.7       379.6       379.6  
   
Retained lease expense, net in operating costs and expenses
    10.4       9.1       9.1       9.1       9.1  
   
Gain on sale of assets in operating costs and expenses
    (0.4 )                     (18.7 )     (18.7 )
   
Selling, general and administrative costs
    30.3       42.9       37.5       92.0       92.0  
     
     
     
     
     
 
Total Gross Operating Margin
  $ 375.9     $ 332.3     $ 410.4     $ 887.3     $ 887.3  
     
     
     
     
     
 
Reconciliation of Non-GAAP “EBITDA” to GAAP “Net income” or “Income from continuing operations” and GAAP “Cash provided by operating activities”
                                       
Net Income (Income from continuing operations with regards to pro forma information)
  $ 242.2     $ 95.5     $ 104.5     $ 103.4     $ 112.5  
 
Adjustments to derive EBITDA:
                                       
   
Interest expense
    52.5       101.6       140.8       321.1       312.0  
   
Provision for income taxes
            1.6       5.3       5.3       5.3  
   
Depreciation and amortization (excluding amortization component in interest expenses)
    51.1       86.1       115.8       379.7       379.7  
     
     
     
     
     
 
EBITDA
    345.8       284.8       366.4     $ 809.5     $ 809.5  
                             
     
 
 
Interest expense
    (52.5 )     (101.6 )     (140.8 )                
 
Amortization in interest expense
    0.8       8.8       12.6                  
 
Provision for income taxes
            (1.6 )     (5.3 )                
 
Provision for impairment charge
                    1.2                  
 
Equity in loss (income) of unconsolidated affiliates
    (25.4 )     (35.3 )     14.0                  
 
Distributions from unconsolidated affiliates
    45.1       57.7       31.9                  
 
Loss (gain) on sale of assets
    (0.4 )                                
 
Operating lease expense paid by EPCO (excluding minority interest portion)
    10.3       9.0       9.0                  
 
Other expenses paid by EPCO
                    0.4                  
 
Minority interest
    2.5       3.0       3.9                  
 
Deferred income tax expense
            2.1       10.5                  
 
Changes in fair market value of financial instruments
    (5.7 )     10.2                          
 
Increase in restricted cash
    (5.7 )     (3.0 )     (5.1 )                
 
Net effect of changes in operating accounts
    (37.2 )     92.7       120.9                  
     
     
     
                 
Cash provided by operating activities
  $ 277.6     $ 326.8     $ 419.6                  
     
     
     
                 

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Non-GAAP Reconciliations (Continued)

                                     
Consolidated Historical

For Nine Months Ended
For Nine Months September 30, 2004
Ended September 30,

Pro Forma
2003 2004 Pro Forma as Adjusted




(Unaudited)
(Dollars in millions)
Reconciliation of Non-GAAP “Gross operating margin” to GAAP “Operating income”
                               
Operating Income
  $ 182.0     $ 247.7     $ 424.3     $ 424.3  
 
Adjustments to reconcile Operating income to Gross operating margin:
                               
   
Depreciation and amortization in operating costs and expenses
    83.8       94.7       287.5       287.5  
   
Retained lease expense, net in operating costs and expenses
    6.8       6.8       6.8       6.8  
   
Loss (gain) on sale of assets in operating costs and expenses
    (0.1 )     0.2       0.2       0.2  
   
Selling, general and administrative costs
    28.9       26.6       73.1       73.1  
     
     
     
     
 
Gross operating margin
  $ 301.4     $ 376.0     $ 791.9     $ 791.9  
     
     
     
     
 
Reconciliation of Non-GAAP “EBITDA” to GAAP “Net income” or “Income from continuing operations” and GAAP “Cash provided by operating activities”
                               
Net income (Income from continuing operations with regards to pro forma information)
    70.4       152.9       216.5       223.3  
 
Adjustments to derive EBITDA:
                               
   
Interest expense
    107.7       96.9       202.5       195.7  
   
Provision for income taxes
    4.6       2.7       2.7       2.7  
   
Depreciation and amortization (excluding amortization component in interest expenses)
    83.8       94.7       287.5       287.5  
     
     
     
     
 
EBITDA
    266.5       347.2     $ 709.2     $ 709.2  
                     
     
 
 
Interest expense
    (107.7 )     (96.9 )                
 
Amortization in interest expense
    12.3       3.2                  
 
Provision for income taxes
    (4.6 )     (2.7 )                
 
Cumulative effect of change in accounting principle
          (10.8 )                
 
Provision for impairment of long-lived asset
          4.0                  
 
Equity in loss (income) of unconsolidated affiliates
    16.6       (42.2 )                
 
Distributions from unconsolidated affiliates
    25.7       54.6                  
 
Loss (gain) on sale of assets
    (0.1 )     0.2                  
 
Operating lease expense paid by EPCO (excluding minority interest portion)
    6.8       6.8                  
 
Other expenses paid by EPCO
    0.6                        
 
Minority interest
    4.4       6.9                  
 
Deferred income tax expense
    4.2       6.3                  
 
Increase in restricted cash
    (5.9 )     (3.1 )                
 
Net effect of changes in operating accounts
    3.9       (240.5 )                
     
     
                 
Cash provided by operating activities
  $ 222.7     $ 33.0                  
     
     
                 

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Non-GAAP Reconciliations (Continued)

      The following table presents a reconciliation of our non-GAAP financial measures of total gross operating margin and EBITDA as presented on page S-7 to their respective GAAP measures.

                                     
For Three Months For the Year Ended
Ended December 31, December 31, 2004


2003 2004 2003 2004




(Unaudited)
(Unaudited)
(Dollars in millions)
Reconciliation of Non-GAAP “Total gross operating margin” to GAAP “Operating income”
                               
Operating income
  $ 66.1     $ 175.3     $ 248.1     $ 423.0  
 
Adjustments to reconcile Operating income to Total gross operating margin:
                               
   
Depreciation and amortization in operating costs and expenses
    31.9       99.1       115.7       193.7  
   
Retained lease expense, net in operating costs and expenses
    2.3       0.9       9.1       7.7  
   
Loss (gain) on sale of assets in operating costs and expenses
          (16.1 )           (15.9 )
   
Selling, general and administrative costs
    8.7       20.0       37.5       46.7  
     
     
     
     
 
Total gross operating margin
  $ 109.0     $ 279.2     $ 410.4     $ 655.2  
     
     
     
     
 
Reconciliation of Non-GAAP “EBITDA” to GAAP “Net income” or “Income from continuing operations” and GAAP “Cash provided by operating activities”
                               
Net income
  $ 34.2     $ 115.4     $ 104.5     $ 268.3  
 
Adjustments to derive EBITDA:
                               
   
Interest expense
    33.1       58.8       140.8       155.7  
   
Provision for income taxes
    0.7       1.0       5.3       3.7  
   
Depreciation and amortization (excluding amortization component in interest expenses)
    31.9       100.4       115.8       195.4  
     
     
     
     
 
EBITDA
  $ 99.9     $ 275.6     $ 366.4     $ 623.1  
     
     
     
     
 

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RISK FACTORS

      An investment in our common units involves risks. You should consider carefully the risk factors included below, under the caption “Risk Factors” beginning on page 2 of the accompanying prospectus, and under “Business and Properties — Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2003, together with all of the other information included in, or incorporated by reference into, this prospectus supplement, when evaluating an investment in our common units. If any of these risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our common units could decline, and you could lose all or part of your investment.

Risks Related to Our Business

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

      We operate predominantly in the midstream energy sector which includes 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 materially adversely affected by changes in the prices of these hydrocarbon products and by changes in the relative price levels among these hydrocarbon products. In general terms, 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;
 
  •  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.

      We are also exposed to natural gas and NGL commodity price risk under natural gas processing and gathering and NGL fractionation contracts that provide for our fee 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 our results of operations, cash flows and financial position.

 
A decline in the volume of natural gas, NGLs and crude oil delivered to our facilities could adversely affect our results of operations, cash flows and financial condition.

      Our profitability could be materially 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.

      The crude oil, natural gas and NGLs available to our facilities will be derived from reserves produced from existing wells, which reserves naturally decline over time. To offset this natural decline, our facilities will need access to additional reserves. Additionally, some of our 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 out of our control and can adversely affect the

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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 our facilities are located. This could result in a decrease in volumes to our offshore platforms, natural gas processing plants, natural gas, crude oil and NGL pipelines, and NGL fractionators which would have a material adverse affect on our results of 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 our 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 our 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.
 
        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, our 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 we produce and expose our 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.
 
We face competition from third parties in our midstream businesses.

      Even if reserves exist in the areas accessed by our facilities and are ultimately produced, we may not be chosen by the producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons that are produced. We compete with others, including producers of oil and natural gas, for any such production on the basis of many factors, including:

  •  geographic proximity to the production;
 
  •  costs of connection;
 
  •  available capacity;
 
  •  rates; and
 
  •  access to markets.

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Our debt level may limit our future financial and operating flexibility.

      As of September 30, 2004, on a pro forma as adjusted basis, we had approximately $4.3 billion of consolidated debt outstanding. The amount of our debt could have significant effects on our future operations, including, among other things:

  •  a significant portion of our cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;
 
  •  credit rating agencies may view our debt level negatively;
 
  •  covenants contained in our existing debt arrangements will require us to continue to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;
 
  •  our ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;
 
  •  we may be at a competitive disadvantage relative to similar companies that have less debt; and
 
  •  we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.

      Our public debt indentures currently do not limit the amount of future indebtedness that we can create, incur, assume or guarantee. Our revolving credit facilities, however, restrict our ability to incur additional debt, though any debt we may incur in compliance with these restrictions may still be substantial.

      Each of our revolving credit facilities and indentures for our public debt contains conventional financial covenants and other restrictions. A breach of any of these restrictions by us 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.

      Our ability to access the capital markets to raise capital on favorable terms will be affected by our debt level, the amount of our debt maturing in the next several years and current maturities, and by adverse market conditions resulting from, among other things, general economic conditions, contingencies and uncertainties that are difficult to predict and impossible to control. Moreover, if the rating agencies were to downgrade our corporate credit, then we could experience an increase in our borrowing costs, difficulty assessing capital markets or a reduction in the market price of our common units. Such a development could adversely affect our ability to obtain financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness. If we are unable to access the capital markets on favorable terms in the future, we might be forced to seek extensions for some of our short-term securities or to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which we 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 our leverage may adversely affect our future financial and operating flexibility and our ability to pay cash distributions at expected rates.

 
We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for qualified assets.

      Our 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 strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, potential joint ventures, stand alone projects or other transactions that we believe will present opportunities to realize synergies, expand our role in the energy infrastructure business and increase our market position.

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      We may require substantial new capital to finance the future development and acquisition of assets and businesses. Limitations on our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire accretive assets. We may not be able to raise the necessary funds on satisfactory terms, if at all.

      In addition, we are experiencing increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in our losing to other bidders more often or acquiring assets at higher prices. Either occurrence would limit our ability to fully execute our growth strategy. Our inability to execute our growth strategy may materially adversely impact the market price of our securities.

 
Our growth strategy may adversely affect our results of operations if we do not successfully integrate the businesses that we acquire, including GulfTerra, or if we substantially increase our indebtedness and contingent liabilities to make acquisitions.

      Our growth strategy includes making accretive acquisitions. As a result, from time to time, we will evaluate and acquire assets and businesses that we believe complement our existing operations. Similar to the risks associated with integrating our operations with GulfTerra’s operations, we may be unable to integrate successfully businesses we acquire in the future. We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could negatively impact our results of operations, cash flows and financial condition. Moreover, acquisitions and business expansions involve numerous risks, including:

  •  difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or business segments;
 
  •  establishing the internal controls and procedures that we are required to maintain under the Sarbanes-Oxley Act of 2002;
 
  •  managing relationships with new joint venture partners with whom we have not previously partnered;
 
  •  inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including with their markets; and
 
  •  diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.

      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, our capitalization and results of operations may change significantly following an acquisition. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our business. In addition, any anticipated benefits of a material acquisition, such as expected cost savings, may not be fully realized, if at all.

 
Our operating cash flows from our capital projects may not be immediate.

      We are engaged in several capital expansion projects and “greenfield” projects for which significant capital has been expended, and our operating cash flow from a particular project may not increase immediately following its completion. For instance, if we build a new pipeline or platform or expand an existing facility, the design, construction, development and installation may occur over an extended period of time, and we may not receive any material increase in operating cash flow from that project until after it is placed in service. If we experience unanticipated or extended delays in generating operating cash flow from these projects, we may be required to reduce or reprioritize our capital budget, sell non-core assets, access the capital markets or decrease distributions to unitholders in order to meet our capital requirements.

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Our actual construction, development and acquisition costs could exceed forecasted amounts.

      We will have significant expenditures for the development, construction or other acquisition 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 600 feet, are very expensive and involve much more uncertainty and risk, and if a problem occurs, the solution, if one exists, may be very expensive and time consuming. We may not be able to complete our projects, whether in deepwater or otherwise, at the costs estimated at the time of initiation.

 
We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint venture participants agree.

      We participate in several joint ventures. Due to the nature of some of these joint ventures, each participant in each of 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 in that joint venture, 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 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, we may be unable to cause any of our 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 our partnering with different or additional parties.

 
The interruption of distributions to us from our subsidiaries and joint ventures may affect our ability to satisfy our obligations and to make cash distributions to our unitholders.

      We are a holding company with no business operations. Our only significant assets are the equity interests we own in our subsidiaries and joint ventures. As a result, we depend upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of that cash to us in order to meet our obligations and to allow us to make distributions to our unitholders.

      In addition, the management committees of the joint ventures in which we participate typically have sole discretion regarding the occurrence and amount of distributions. Some of the joint ventures in which we participate have separate credit arrangements that contain various restrictive covenants. Among other things, those covenants may limit or restrict the joint venture’s ability to make distributions to us under certain circumstances. Accordingly, our joint ventures may be unable to make distributions to us at current levels or at all.

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

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

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      If one or more facilities that are owned by us or that deliver oil, natural gas or other products to us are damaged by severe weather or any other disaster, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Additionally, some of the storage contracts that we are a party to obligate us to indemnify our customers for any damage or injury occurring during the period in which the customers’ natural gas is in our possession. Any event that interrupts the fees generated by our energy infrastructure assets, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying our interest obligations as well as unitholder distributions and, accordingly, adversely affect the market price of our securities.

      We believe that we maintain adequate insurance coverage, 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, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

 
An impairment of goodwill could reduce our earnings.

      We had recorded $445.9 million of goodwill and $961.9 million of intangible assets on our consolidated balance sheet as of September 30, 2004. 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 will require us 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 we determine that any of our goodwill or intangible assets were impaired, we 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.

 
Increases in interest rates could adversely affect our business and may cause the market price of our common units to decline.

      In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of December 31, 2004, we had approximately $4.3 billion of consolidated debt, of which approximately $2.9 billion was at fixed interest rates and approximately $1.4 billion was at variable interest rates, after giving effect to existing interest swap arrangements. We may from time to time enter into additional interest rate swap arrangements, which could increase our exposure to variable interest rates. As a result, our results of operations, cash flows and financial condition, could be materially adversely affected by significant increases in interest rates.

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

 
The use of derivative financial instruments could result in material financial losses by us.

      We historically have 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 we hedge our commodity price and interest rate exposures, we will forego the benefits we would otherwise experience if commodity prices or interest rates were

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to change in our favor. In addition, even though monitored by 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.
 
Our pipeline integrity program may impose significant costs and liabilities on us.

      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, we cannot predict the outcome of this rule on us. However, we will continue our pipeline integrity testing programs, which are intended to assess and maintain the integrity of our pipelines. While the costs associated with the pipeline integrity testing itself are not large, the results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

 
Environmental costs and liabilities and changing environmental regulation could materially affect our cash flow.

      Our operations are subject to extensive federal, state and local regulatory requirements relating to environmental affairs, health and safety, waste management and chemical and petroleum products. 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.

      We will make expenditures in connection with environmental matters as part of normal capital expenditure programs. However, future environmental law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations, including the handling, manufacture, use, emission or disposal of substances and wastes. Moreover, as with other companies engaged in similar or related businesses, our operations have some risk of environmental costs and liabilities because we handle petroleum products.

 
Federal, state or local regulatory measures could materially adversely affect our business.

      The Federal Energy Regulatory Commission, or FERC, regulates our interstate natural gas pipelines and interstate NGL and petrochemical pipelines, while state regulatory agencies regulate our intrastate natural gas and NGL pipelines, intrastate storage facilities and gathering lines. This federal and state regulation extends to such matters as:

  •  rate structures;
 
  •  rates of return on equity;
 
  •  recovery of costs;
 
  •  the services that our regulated assets are permitted to perform;
 
  •  the acquisition, construction and disposition of assets; and
 
  •  to an extent, the level of competition in that regulated industry.

      Our 2003 Annual Report on Form 10-K, which is incorporated by reference into this prospectus, contains a general overview of FERC and state regulation applicable to our energy infrastructure assets. This regulatory oversight can affect certain aspects of our business and the market for our products and could materially adversely affect our cash flow. Please read “Business and Properties — Regulation and Environmental Matters” in our Annual Report on Form 10-K for the year ended December 31, 2003.

      Under the Natural Gas Act, FERC has authority to regulate our natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services

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includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters. Pursuant to FERC’s jurisdiction over interstate gas pipeline rates, existing pipeline rates may be challenged by complaint and proposed rate increases may be challenged by protest.

      For example, in December 2002, High Island Offshore System, L.L.C., or HIOS, an interstate natural gas pipeline owned by us, filed a rate case pursuant to Section 4 of the Natural Gas Act before FERC to increase its transportation rates. FERC accepted HIOS’ tariff sheets implementing the new rates, subject to refund, and set certain issues for hearing before an Administrative Law Judge, or ALJ. The ALJ issued an initial decision on the issues set for hearing on April 22, 2004, proposing rates lower than the rate initially proposed by HIOS. In response to the ALJ’s initial decision, HIOS filed, on August 5, 2004, a settlement agreement whereby HIOS proposed to implement its rates in effect prior to this proceeding for a prospective three-year period.

      On January 24, 2005, FERC issued an order rejecting HIOS’s settlement offer and generally affirming the ALJ’s initial decision, resulting in rates significantly lower than the rate proposed in HIOS’ settlement offer. FERC’s January 24 order may be subject to requests for rehearing and appeal to federal court. We are 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 we may be a party in the future could adversely affect our results of operations, cash flows and financial position.

      FERC also has authority under the Interstate Commerce Act, or ICA, to regulate the rates, terms, and conditions applied to our interstate pipelines engaged in the transportation of NGLs and petrochemicals (commonly known as “oil pipelines”). Pursuant to the ICA, oil pipeline rates can be challenged at FERC either by protest, when they are initially filed or increased, or by complaint at any time they remain on file with the jurisdictional agency.

      We have interests in natural gas pipeline facilities offshore from Texas and Louisiana. These facilities are subject to regulation by 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.

      Our intrastate NGL and gas pipelines are subject to regulation in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. We also have natural gas underground storage facilities in Louisiana, Mississippi and Texas. Although state regulation is typically less onerous than at FERC, proposed and existing rates subject to state regulation are also subject to challenge by protest and complaint, respectively.

      We are subject to ratable take and common purchaser statutes in certain states where we operate. Ratable take statues generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate that have adopted some form of complaint-based regulation, like Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.

      Certain of our companies, assets and services are regulated by FERC, including its interstate natural gas pipeline system, interstate natural gas storage facilities and service provided by its intrastate natural gas pipelines pursuant to Section 311 of the Natural Gas Policy Act, or NGPA.

      Additionally, 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 NGPA. In June 2002, the FERC issued an order that required revisions to GulfTerra Texas’ proposed maximum rates.

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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. In July 2002, GulfTerra Texas requested rehearing on certain issues raised by the FERC’s order, including the depreciation rates and the requirement to state separately a gathering rate. On February 25, 2004, the FERC issued an order denying GulfTerra Texas’ request for rehearing and ordering GulfTerra Texas to file a calculation of refunds and a refund plan. GulfTerra Texas filed that information with the FERC on July 12, 2004. GulfTerra Texas’s filing includes its calculation of approximately $1,200 in refunds due to GulfTerra Texas and notes that GulfTerra Texas would update the calculation, upon a final FERC order in the proceeding, to include any additional amounts, including interest due to GulfTerra Texas. The Commission, by letter dated January 11, 2005, is seeking additional information from GulfTerra Texas regarding its July 12, 2004 filing, thus, a final FERC order is still pending. Additionally, the FERC’s February 25, 2004 order directed GulfTerra Texas to file a new rate case or justification of existing rates every three years. GulfTerra Texas filed a timely request for rehearing of the triennial rate filing requirement, which the Commission rejected, on December 27, 2004.

      On July 20, 2004, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in BP West Coast Products, LLC v. FERC, which upheld FERC’s determination that 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. The court also stated that FERC had not provided reasonable decision-making in support of its Lakehead policy. In Lakehead, the FERC allowed a regulated entity organized as a master limited partnership to include in its cost of service an income tax allowance to the extent that its unitholders were corporations subject to income tax. The court remanded the issue of the appropriate income tax allowance for a pipeline owned by a master limited partnership and 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. Because the court remanded to the FERC and because the FERC’s ruling will focus on the facts and record presented to it, it is not clear what impact, if any, the opinion will have on our rates or on the rates of other FERC-jurisdictional pipelines organized as tax pass-through entities. On December 2, 2004, the FERC issued a Notice of Inquiry in Docket No. PL05-5 suggesting that BP West Coast may not be limited to the specific facts. Specifically, FERC requested comments regarding whether the court’s opinion should apply only to the specific facts of that case, or whether it should apply more broadly, and, if the latter, what effect that ruling might have on energy infrastructure investments. It is not clear what action the FERC will take in response to BP West Coast after considering comments filed, to what extent such action will be challenged and, if so, whether it will withstand further FERC or judicial review.

Risk Related to Our Common Units as a Result of Our Partnership Structure

 
A large number of our outstanding common units may be sold in the market following this offering, which may depress the market price of our common units.

      Sales of a substantial number of our common units in the public market following this offering could cause the market price of our common units to decline. Upon completion of this offering, a total of approximately 374,785,865 of our common units will be outstanding. Shell US Gas & Power LLC, which will own 36,572,122 of our common units following this offering, representing approximately 9.6% of our outstanding common units after giving effect to this offering, has publicly announced its intention to reduce its holdings of our common units on an orderly schedule over a period of years, taking into account market conditions. Under a registration rights agreement, we are obligated, subject to certain limitations and conditions, to register the common units held by Shell US Gas & Power for resale.

      Sales of a substantial number of these units in the trading markets, whether in a single transaction or series of transactions, or the possibility that these sales may occur, could reduce the market price of our outstanding common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

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USE OF PROCEEDS

      We expect to receive net proceeds of approximately $266.5 million (assuming a public offering price of $27.28) from the sale of the 10,000,000 common units we are offering (including the net capital contribution of $5.4 million from our general partner to maintain its 2% general partner interest) after deducting underwriting discounts, commissions and estimated offering expenses payable by us. If the underwriters exercise their over-allotment option in full, we will receive net proceeds of approximately $306.5 million, including a proportionate net capital contribution of $6.1 million from our general partner.

      We will use a portion of the net proceeds from this offering, including our general partner’s proportionate capital contribution, to permanently reduce borrowings and commitments outstanding under our 364-day acquisition revolving credit facility, which indebtedness was incurred to fund a portion of the purchase price at the closing of the GulfTerra merger and related transactions on September 30, 2004. Any remaining proceeds will be used for general partnership purposes, which may include acquisitions or the temporary reduction of amounts borrowed under our revolving credit facilities. We will use the net proceeds from any exercise of the underwriters’ over-allotment option, including any additional capital contribution from our general partner, in the manner discussed in the preceding sentence.

      As of January 31, 2005, we had $242.2 million of borrowings outstanding under our 364-day acquisition revolving credit facility that bear interest at a rate of approximately 3.4% per annum, and we had $493.0 million of borrowings outstanding under our multi-year revolving credit facility that bear interest at a rate of approximately 3.4% per annum. Amounts repaid on our multi-year revolving credit facility may be reborrowed from time to time.

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

      On December 31, 2004, we had 364,293,458 common units outstanding, beneficially held by approximately 100,000 holders. Our common units are traded on the New York Stock Exchange under the symbol “EPD.”

      The following table sets forth, for the periods indicated, the high and low sales price ranges for our common units, as reported on the New York Stock Exchange Composite Transaction Tape, and the amount, record date and payment date of the quarterly cash distributions paid per common unit. The last reported sales price of our common units on the New York Stock Exchange on February 3, 2005 was $27.28 per common unit.

                                           
Cash Distribution History
Price Ranges

Per
High Low Unit(1) Record Date Payment Date





2003
                                       
 
1st Quarter
  $ 21.00     $ 17.85     $ 0.3625       April 30, 2003       May 12, 2003  
 
2nd Quarter
    24.69       20.62       0.3625       July 31, 2003       August 11, 2003  
 
3rd Quarter
    24.10       20.25       0.3725       October 31, 2003       November 12, 2003  
 
4th Quarter
    24.98       20.76       0.3725       January 30, 2004       February 11, 2004  
2004
                                       
 
1st Quarter
  $ 24.72     $ 21.75     $ 0.3725       April 30, 2004       May 12, 2004  
 
2nd Quarter
    23.84       20.00       0.3725       July 30, 2004       August 6, 2004  
 
3rd Quarter
    23.70       20.19       0.3950       October 29, 2004       November 5, 2004  
 
4th Quarter
    25.99       22.73       0.4000 (2)     January 31, 2005       February 14, 2005  
2005
                                       
 
1st Quarter
(through February 3, 2005)
  $ 28.35     $ 24.85       (3)            


(1)  For each quarter, we paid an identical cash distribution on all outstanding subordinated units. The remaining outstanding subordinated units converted into an equal number of common units on August 1, 2003. In addition, we paid an identical cash distribution per unit to the holder of our Class B special units prior to their conversion to common units on July 29, 2004.
 
(2)  On January 19, 2005, our general partner increased our quarterly cash distribution to $0.40 per common unit, or $1.60 per common unit on an annualized basis, beginning with cash distributions with respect to the fourth quarter of 2004. The distribution with respect to the fourth quarter will be paid on February 14, 2005 to unitholders of record on January 31, 2005. The units purchased in this offering will not be entitled to receive this distribution.
 
(3)  Distributions with respect to quarters subsequent to the fourth quarter of 2004 have neither been declared nor paid.

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CAPITALIZATION

      The following table sets forth our capitalization as of September 30, 2004:

  •  on a consolidated historical basis;
 
  •  on a pro forma basis giving effect to the following adjustments:

  •  the issuance by our operating partnership of $2 billion of senior unsecured notes on October 4, 2004, and the application of the net proceeds therefrom to reduce debt amounts outstanding under our 364-day acquisition revolving credit facility that was used to fund a portion of the purchase price at the closing of the GulfTerra merger and related transactions on September 30, 2004;
 
  •  the completion on October 5, 2004 of our 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 in cash borrowed under our 364-day acquisition revolving credit facility, which was placed in escrow on September 30, 2004;
 
  •  our issuance of 2,199,350 common units in connection with the DRIP in November 2004; and
 
  •  the conversion of the remaining outstanding 80 Series F2 convertible units, which were originally issued by GulfTerra, into an aggregate of 1,950,317 of our common units in November and December 2004; and

  •  on a pro forma as adjusted basis to give effect to the issuance of 10,000,000 common units in this offering at an assumed offering price of $27.28, our general partner’s proportionate capital contribution and the application of the net proceeds from this offering to reduce borrowings under our revolving credit facilities.

      The historical data in the table on the following page are derived from and should be read in conjunction with our historical financial statements, including the accompanying notes, incorporated by reference in this prospectus supplement. Please read our unaudited pro forma financial statements included elsewhere in this prospectus supplement for a complete description of the adjustments we have made to arrive at the pro forma financial measures that we present in the following table. You should also read our financial statements and notes that are incorporated by reference in this prospectus supplement for additional information regarding our capital structure.

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Enterprise Historical and Pro Forma Capitalization

As of September 30, 2004
                               
Pro Forma
Historical Pro Forma As Adjusted



(Dollars in millions)
Cash and cash equivalents
  $ 146.6     $ 234.0     $ 234.0  
     
     
     
 
Long-term borrowings including current portion:
                       
 
Enterprise amounts:
                       
   
364-Day Acquisition Revolving Credit Facility, variable rate, due September 2005, $2.25 billion borrowing capacity
  $ 2,250.0     $ 265.5        
   
Multi-Year Revolving Credit Facility “B”, variable rate, due September 2009, $750 million borrowing capacity
    545.0       545.0     $ 544.0  
   
Senior Notes A, 8.25% fixed-rate, due March 2005
    350.0       350.0       350.0  
   
Seminole Notes, 6.67% fixed-rate, $15 million due in December 2004 and 2005
    30.0       30.0       30.0  
   
MBFC Loan, 8.70% fixed-rate, due March 2010
    54.0       54.0       54.0  
   
Senior Notes B, 7.50% fixed-rate, due February 2011
    450.0       450.0       450.0  
   
Senior Notes C, 6.375% fixed-rate, due February 2013
    350.0       350.0       350.0  
   
Senior Notes D, 6.875% fixed-rate, due March 2033
    500.0       500.0       500.0  
   
Senior Notes E, 4.00% fixed-rate, due October 2007
            500.0       500.0  
   
Senior Notes F, 4.625% fixed-rate, due October 2009
            500.0       500.0  
   
Senior Notes G, 5.60% fixed-rate, due October 2014
            650.0       650.0  
   
Senior Notes H, 6.65% fixed-rate, due October 2034
            350.0       350.0  
 
GulfTerra amounts:
                       
   
Senior Notes, 6.25% fixed-rate, due June 2010
    250.0       0.7       0.7  
   
Senior Subordinated Notes, 8.50% fixed-rate, due June 2010
    215.9       3.9       3.9  
   
Senior Subordinated Notes, 8.50% fixed-rate, due June 2011
    321.6       1.8       1.8  
   
Senior Subordinated Notes, 10.625% fixed-rate, due December 2012
    134.0       0.1       0.1  
   
Fair value of GulfTerra notes at merger closing date
    132.4              
     
     
     
 
     
Total principal amount
    5,582.9       4,551.0       4,284.5  
 
Other
    (3.5 )     (19.0 )     (19.0 )
     
     
     
 
     
Total debt obligations
    5,579.4       4,532.0       4,265.5  
Minority interest
    61.3       61.3       61.3  
Partners’ equity:
                       
 
Common units, including restricted common units
    5,164.4       5,251.5       5,512.6  
 
General partner
    105.4       107.2       112.6  
 
Accumulated other comprehensive income
    24.1       24.1       24.1  
 
Other
    (14.3 )     (14.3 )     (14.3 )
     
     
     
 
     
Total partners’ equity
    5,279.6       5,368.5       5,635.0  
     
     
     
 
     
Total capitalization
  $ 10,920.3     $ 9,961.8     $ 9,961.8  
     
     
     
 

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BUSINESS AND PROPERTIES

Our Business and Properties

      Formed in 1998 as a limited partnership, we are a leading North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, natural gas liquids, or NGLs, and crude oil and we are an industry leader in the development of midstream infrastructure in the deepwater trend of the Gulf of Mexico. We provide integrated services to our customers and generate fee-based cash flow from multiple sources along our midstream energy value chain.

      Our midstream energy services include:

  •  gathering and transportation of raw natural gas from both onshore and offshore Gulf of Mexico developments;
 
  •  gathering and transportation of crude oil from offshore Gulf of Mexico developments;
 
  •  offshore production platform services;
 
  •  processing of raw natural gas into a marketable product that meets industry quality specifications by removing mixed NGLs and impurities;
 
  •  purchase of natural gas for resale to our industrial, utility and municipal customers;
 
  •  transportation of mixed NGLs to fractionation facilities by pipeline;
 
  •  fractionation (or separation) of mixed NGLs produced as by-products of crude oil refining and natural gas production into component NGL products: ethane, propane, isobutane, normal butane and natural gasoline;
 
  •  transportation of NGL products to end-users by pipeline, railcar and truck;
 
  •  import and export of NGL products and petrochemical products through our dock facilities;
 
  •  fractionation of refinery-sourced propane/propylene mix into high-purity propylene, propane and mixed butane;
 
  •  transportation of high-purity propylene to end-users by pipeline;
 
  •  storage of natural gas, mixed NGLs, NGL products and petrochemical products;
 
  •  conversion of normal butane to isobutane through the process of isomerization;
 
  •  production of high-octane additives for motor gasoline from isobutane; and
 
  •  sale of NGLs and petrochemical products we produce and/or purchase for resale.

      In addition to our current strategic position in the Gulf of Mexico, we have access to major natural gas and NGL supply basins throughout the United States and Canada, including the Rocky Mountains, the San Juan and Permian basins, the Mid-Continent region and, through third-party pipeline connections, north into Canada’s Western Sedimentary basin. Our system of assets in the Gulf Coast region of the United States, combined with our Mid-America and Seminole pipeline systems, create the only integrated North American midstream network.

Our Business Segments

      As a result of the GulfTerra merger and related transactions, we have reorganized our 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. Our business segments are generally organized and managed along our midstream energy value chain according to the type of services rendered and products produced and sold.

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Offshore Pipelines & Services

      Our Offshore Pipelines & Services business segment consists of:

  •  approximately 1,390 miles of offshore natural gas pipelines strategically located to serve production activities in some of the most active drilling and development regions in the Gulf of Mexico;
 
  •  ownership interests in offshore oil pipeline systems aggregating approximately 800 miles, which are strategically located in the vicinity of some prolific oil-producing regions in the Gulf of Mexico;
 
  •  ownership interests in seven multi-purpose offshore hub platforms located in the Gulf of Mexico which are used to process production from offshore oil and natural gas developments, interconnect our offshore pipeline grid and assist in performing pipeline maintenance; and
 
  •  ownership interests in four minor oil and natural gas producing properties located in the waters offshore of Louisiana.
 
Onshore Natural Gas Pipelines & Services

      Our Onshore Natural Gas Pipelines & Services business segment includes onshore natural gas pipeline systems aggregating approximately 17,180 miles that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. Included in this segment are two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast natural gas markets. We also lease natural gas storage facilities located in Texas and Louisiana.

 
NGL Pipelines & Services

      Our NGL Pipelines & Services business segment consists of:

  •  our natural gas processing business and related NGL marketing activities;
 
  •  NGL pipelines aggregating approximately 12,600 miles and related storage facilities, which include our strategic Mid-America and Seminole NGL pipeline systems;
 
  •  NGL fractionation facilities located in Texas and Louisiana; and
 
  •  our import and export terminaling operations.

      At the core of our natural gas processing business are 24 processing plants, located primarily in south Louisiana, south Texas and New Mexico, that process raw natural gas into a product that meets pipeline and industry specifications by removing NGLs and impurities. In connection with our processing business, we receive a portion of the NGL production from the gas plants. This equity NGL production, together with the NGLs we purchase, supports the NGL marketing activities included in this business segment. Additionally, our NGL pipelines transport mixed NGLs and other hydrocarbons to fractionation plants, distribute and collect NGL products to and from petrochemical plants and refineries. Our NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline.

 
Petrochemical Services

      Our Petrochemical Services business segment includes our four propylene fractionation facilities, isomerization complex, and octane additive production facility. This segment also includes approximately 460 miles of various propylene pipeline systems and a 70-mile hi-purity isobutane pipeline.

      Our propylene fractionation facilities separate refinery-sourced propane/propylene mix into propane, propylene and mixed butane. Our isomerization complex converts normal butane into isobutane.

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MANAGEMENT

Our Management

      The following table sets forth certain information with respect to the executive officers and members of the board of directors of our general partner. Executive officers and directors are elected for one-year terms.

             
Position with General Partner
Name Age of Enterprise



Dan L. Duncan
    72     Director and Chairman of the Board
O.S. Andras
    69     Director and Vice Chairman of the Board and Chief Executive Officer
Robert G. Phillips
    50     Director and President and Chief Operating Officer
Dr. Ralph S. Cunningham
    63     Director*
Lee W. Marshall, Sr.
    71     Director*
W. Matt Ralls
    55     Director*
Richard S. Snell
    62     Director*
Richard H. Bachmann
    52     Executive Vice President, Secretary and Chief Legal Officer
Michael A. Creel
    51     Executive Vice President and Chief Financial Officer
James H. Lytal
    47     Executive Vice President
A. James Teague
    59     Executive Vice President
Charles E. Crain
    71     Senior Vice President
W. Ordemann
    45     Senior Vice President
Gil H. Radtke
    43     Senior Vice President
James M. Collingsworth
    49     Senior Vice President
James A. Cisarik
    46     Senior Vice President
Lynn L. Bourdon, III
    43     Senior Vice President
Bart H. Heijermans
    38     Senior Vice President
Richard H. Hoover
    48     Senior Vice President
Joel D. Moxley
    46     Senior Vice President
Michael J. Knesek
    50     Vice President, Controller and Principal Accounting Officer
W. Randall Fowler
    48     Vice President and Treasurer


Independent directors

      Dan L. Duncan was elected Chairman and a Director of our general partner, Enterprise Products GP, LLC, in April 1998. Mr. Duncan has served as Chairman of the Board of our predecessor, EPCO, Inc., or EPCO, since 1979.

      O.S. Andras was elected Chief Executive Officer, Vice Chairman and a Director of our general partner in September 2004. Mr. Andras served as President, Chief Executive Officer and a Director of our general partner from April 1998 until September 2004. Mr. Andras served as President and Chief Executive Officer of EPCO from 1996 to February 2001 and currently serves as Vice Chairman of the Board of EPCO.

      Robert G. Phillips was elected President, Chief Operating Officer and Director of our general partner in September 2004. Mr. Phillips served as a Director of GulfTerra’s general partner from August 1998 until September 2004. 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

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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 June 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, Mr. Phillips was Chief Executive Officer of Eastex Energy, Inc.

      Dr. Ralph S. Cunningham was elected a Director of our general partner in April 1998. Dr. Cunningham retired in 1997 from CITGO Petroleum Corporation, where he had served as President and Chief Executive Officer since 1995. Dr. Cunningham serves as a director of Tetra Technologies, Inc. (a publicly traded energy services and chemicals company), EnCana Corporation (a Canadian publicly traded independent oil and natural gas company) and Agrium, Inc. (a Canadian publicly traded agricultural chemicals company) and was a director of EPCO from 1987 to 1997. Dr. Cunningham serves as Chairman of our general partner’s Audit and Conflicts Committee and is a member of our general partner’s Governance Committee.

      Lee W. Marshall, Sr. was elected a Director of our general partner in April 1998. Mr. Marshall has been the Managing Partner and principal owner of Bison Resources, LLC, (a privately held oil and gas production company) since 1993. Previously, he held senior management positions with Union Pacific Resources, as Senior Vice President, Refining, Manufacturing and Marketing, with Wolverine Exploration Company as Executive Vice President and Chief Financial Officer and with Tenneco Oil Company as Senior Vice President, Marketing. Mr. Marshall is a member of our general partner’s Audit and Conflicts Committee.

      W. Matt Ralls was elected a Director of our general partner in September 2004. Mr. Ralls served as a Director of GulfTerra’s general partner from May 2003 to September 2004 and is the Senior Vice President and Chief Financial Officer of GlobalSantaFe, an international contract drilling company. 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 Kelley Oil and Gas Corporation and as Vice President of Capital 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 at the senior management level. Mr. Ralls is a member of our general partner’s Audit and Conflicts Committee and serves as Chairman of our general partner’s Governance Committee.

      Richard W. Snell was elected a Director of our general partner 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 law firm of Thompson & Knight LLP in Houston, Texas. Mr. Snell is also a certified public accountant. Mr. Snell is a member of our general partner’s Governance Committee.

      Richard H. Bachmann was elected Executive Vice President, Chief Legal Officer and Secretary of our general partner and EPCO in January 1999. Mr. Bachmann served as a director of our general partner from June 2000 to January 2004.

      Michael A. Creel was elected an Executive Vice President of our general partner and EPCO in February 2001, having served as a Senior Vice President of our general partner and EPCO since November 1999. In June 2000, Mr. Creel, a certified public accountant, assumed the role of Chief Financial Officer of our general partner and EPCO along with his other responsibilities.

      James H. Lytal was elected Executive Vice President of our general partner 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 the 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 United Gas Pipeline Company, Texas Oil and Gas, Inc. and American Pipeline Company.

      A. James Teague was elected an Executive Vice President of our general partner in November 1999. From 1998 to 1999 he served as President of Tejas Natural Gas Liquids, LLC, then a Shell affiliate.

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      Charles E. Crain was elected a Senior Vice President of our general partner in April 1998. Mr. Crain served as Senior Vice President of Operations for EPCO from 1991 to 1998.

      William Ordemann joined us as a Vice President of our general partner 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 our general partner in February 2002. Mr. Radtke joined us in connection with our purchase of Diamond-Koch’s storage and propylene fractionation assets in January and February 2002. Before joining us, 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 our general partner 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 our general partner in February 2003. Mr. Cisarik joined us in April 2001 when we acquired Acadian Gas from Shell. His primary responsibility since joining us has been oversight of the commercial activities of our natural gas businesses, principally those of Acadian Gas and our 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 our general partner on December 10, 2003. His primary responsibility since joining us 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, and 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 our general partner in September 2004. Mr. Heijermans served as GulfTerra’s Vice President, Offshore from June 2003 until September 2004. From June 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, United Kingdom and United States of America.

      Richard A. Hoover was elected Senior Vice President of our general partner 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 Gas Pipeline Corporation, Panda Energy Corporation and Champlin Petroleum Corporation.

      Joel D. Moxley was elected Senior Vice President of our general partner 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-

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Texas where he had responsibilities for gas processing, gas 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.

      Michael J. Knesek was elected Principal Accounting Officer and a Vice President of our general partner in August 2000. Since 1990, Mr. Knesek, a certified public accountant, has been the Controller and a Vice President of EPCO.

      W. Randall Fowler joined us as director of investor relations in January 1999 and was elected to the positions of Treasurer and a Vice President of our general partner and EPCO in August 2000.

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TAX CONSEQUENCES

      The tax consequences to you of an investment in common units will depend in part on your own tax circumstances. For a discussion of the principal federal income tax considerations associated with our operations and the ownership and disposition of common units, please read “Tax Consequences” beginning on page 39 of the accompanying prospectus. We recommend that you consult your own tax advisor about the federal, state, local and foreign tax consequences that are specific to your particular circumstances.

      We estimate that if you purchase common units in this offering and own them through December 31, 2007, then 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. If you own common units purchased in this offering for a shorter period, the percentage of federal taxable income allocated to you may be higher. These estimates are based upon the assumption that our available cash for distribution will approximate the amount required to distribute cash to the holders of the common units in an amount equal to the quarterly distribution of $0.40 per unit 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 certain tax reporting positions that we have adopted with which the IRS could disagree. In addition, subsequent issuances of equity securities by us could also affect the percentage of distributions that will constitute taxable income. Accordingly, we cannot assure you that the estimates will be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units.

      Ownership of common units by tax-exempt entities, regulated investment companies and foreign investors raises issues unique to such persons. 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 beginning after October 22, 2004, the date of enactment. For taxable years beginning prior to the date of enactment, very little of our income will be qualifying income to a regulated investment company. Please read “Tax Consequences — Tax-Exempt Organizations and Other Investors” in the accompanying prospectus.

      The top marginal United States federal income tax rate for individuals is currently 35%. In general, net capital gains of an individual are subject to a maximum 15% United States federal income tax rate if the asset disposed of was held for more than twelve months at the time of disposition.

      No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of the operating partnership as partnerships for federal income tax purposes. Instead, we will rely on the opinion of counsel that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we and the operating partnership will be classified as a partnership for federal income tax purposes.

      In rendering its opinion, counsel has relied on factual representations made by us and the general partner. The representations made by us and our general partner upon which counsel has relied include:

        (a) Neither we nor the operating partnership will elect to be treated as a corporation; and
 
        (b) For each taxable year, more than 90% of our gross income will be income from sources that our counsel has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

      For an explanation of the consequences if we fail to meet the “qualifying income” exception, please read “Tax Consequences — Partnership Status” in the accompanying prospectus.

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UNDERWRITING

      We are offering the common units described in this prospectus through the underwriters named below. UBS Securities LLC and Citigroup Global Markets Inc. are acting as joint book-running managers and representatives of the underwriters.

      Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus supplement, which we will file as an exhibit to a Form 8-K following the pricing of this offering, each underwriter named below has agreed to purchase from us the number of common units set forth opposite the underwriter’s name.

           
Number of
Name of Underwriter Common Units


UBS Securities LLC
       
Citigroup Global Markets Inc.
       
Goldman, Sachs & Co.
       
Lehman Brothers Inc.
       
Morgan Stanley & Co. Incorporated
       
Wachovia Capital Markets, LLC
       
A.G. Edwards & Sons, Inc.
       
Merrill Lynch, Pierce, Fenner & Smith
Incorporated
       
Raymond James & Associates, Inc.
       
Sanders Morris Harris Inc.
       
RBC Capital Markets Corporation
       
KeyBanc Capital Markets, a Division of McDonald Investments Inc.
       
     
 
 
Total
    10,000,000  
     
 

      The underwriting agreement provides that the underwriters’ obligations to purchase the common units depend on the satisfaction of the conditions contained in the underwriting agreement, and that if any of the common units are purchased by the underwriters, all of the common units must be purchased. The conditions contained in the underwriting agreement include the condition that all the representations and warranties made by us and our affiliates to the underwriters are true, that there has been no material adverse change in the condition of us or in the financial markets and that we deliver to the underwriters customary closing documents.

Over-Allotment Option

      We have granted to the underwriters an option to purchase up to an aggregate of 1,500,000 additional common units at the offering price to the public less the underwriting discount set forth on the cover page of this prospectus supplement exercisable to cover over-allotments. Such option may be exercised in whole or in part at any time until 30 days after the date of this prospectus supplement. If this option is exercised, each underwriter will be committed, subject to satisfaction of the conditions specified in the underwriting agreement, to purchase a number of additional common units proportionate to the underwriter’s initial commitment as indicated in the preceding table, and we will be obligated, pursuant to the option, to sell these common units to the underwriters.

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Commissions and Expenses

      The following table shows the underwriting fees to be paid to the underwriters by us in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. This underwriting fee is the difference between the offering price to the public and the amount the underwriters pay to us to purchase the common units.

                   
Paid By Us

No Exercise Full Exercise


Per common unit
  $       $    
 
Total
  $       $    

      We have been advised by the underwriters that the underwriters propose to offer the common units directly to the public at the offering price to the public set forth on the cover page of this prospectus supplement and to dealers (who may include the underwriters) at this price to the public less a concession not in excess of $           per common unit. The underwriters may allow, and the dealers may reallow, a concession not in excess of $           per common unit to certain brokers and dealers. After the offering, the underwriters may change the offering price and other selling terms.

      We estimate that total expenses of the offering, other than underwriting discounts and commissions, will be approximately $1,000,000.

Indemnification

      We and certain of our affiliates have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities.

Lock-Up Agreements

      We, certain of our affiliates, the directors and executive officers of our general partner and an affiliate of Shell have agreed that we and they will not, directly or indirectly, sell, offer, pledge or otherwise dispose of any common units or enter into any derivative transaction with similar effect as a sale of common units for a period of 60 days after the date of this prospectus supplement without the prior written consent of UBS Securities LLC and Citigroup Global Markets Inc. The restrictions described in this paragraph do not apply to:

  •  the issuance and sale of common units by us to the underwriters pursuant to the underwriting agreement;
 
  •  the issuance and sale of common units, phantom units, restricted units and options under our existing employee benefits plans;
 
  •  the issuance and sale of common units pursuant to our distribution reinvestment plan; or
 
  •  the potential sale of certain common units held by the affiliate of Shell pursuant to an outstanding purchase option. The number of common units that may be acquired pursuant to this option is that number of common units equal to the aggregate purchase price of $50,000,000 divided by 0.935 times the average closing price of common units on the NYSE during the 20-day trading period terminating five trading days prior to the date 90 days from December 31, 2004. The reference date for making this calculation may be deferred by an additional ten trading days under certain circumstances.

      UBS Securities LLC and Citigroup Global Markets Inc. may release the units subject to lock-up agreements in whole or in part at any time with or without notice. When determining whether or not to release units from lock-up agreements, UBS Securities LLC and Citigroup Global Markets Inc. will consider, among other factors, our unitholders’ reasons for requesting the release, the number of common units for which the release is being requested and market conditions at the time.

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Price Stabilization, Short Positions And Penalty Bids

      In connection with this offering, the underwriters may engage in stabilizing transactions, overallotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.

  •  Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
 
  •  Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing common units in the open market.
 
  •  Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. If the underwriters sell more common units than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.
 
  •  Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

      These stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

      Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, if commenced, will not be discontinued without notice.

Listing

      Our common units are traded on the New York Stock Exchange under the symbol “EPD.”

Affiliations

      Some of the underwriters and their affiliates have performed investment banking, commercial banking and advisory services for us from time to time for which they have received customary fees and expenses. The underwriters and their affiliates may, from time to time in the future, engage in transactions with and perform services for us in the ordinary course of business.

      Affiliates of UBS Securities LLC, Citigroup Global Markets Inc., Lehman Brothers Inc., Morgan Stanley & Co. Incorporated, Wachovia Capital Markets, LLC and RBC Capital Markets Corporation are lenders under our 364-day acquisition revolving credit facility. These affiliates will receive their respective

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share of any repayment by us of amounts outstanding under the 364-day acquisition revolving credit facility from the proceeds of this offering. Because we intend to use more than 10% of the net proceeds from this offering to reduce indebtedness owed by us to such affiliates, this offering is being conducted in compliance with the requirements of Rule 2710(h) of the Conduct Rules of the National Association of Securities Dealers, Inc.

      In addition, affiliates of UBS Securities LLC, Citigroup Global Markets Inc., Lehman Brothers Inc., Morgan Stanley & Co. Incorporated, Wachovia Capital Markets, LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets Corporation and KeyBanc Capital Markets, a Division of McDonald Investments Inc. are lenders under our multi-year revolving credit facility.

NASD Conduct Rules

      Because the National Association of Securities Dealers, Inc. views the common units offered by this prospectus as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules.

Electronic Distribution

      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 common units to underwriters for sale to their online brokerage account holders. The representatives will allocate common units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common 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.

LEGAL MATTERS

      Certain legal matters with respect to the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters with respect to the common 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 supplement, the accompanying prospectus, the registration statement of which they are a part and the related transaction documents beneficially own approximately 3,200 common units of Enterprise.

EXPERTS

      The (1) consolidated financial statements and the related consolidated financial statement schedule of Enterprise Products Partners L.P. and subsidiaries as incorporated in this prospectus supplement, by reference from Enterprise Products Partners L.P.’s 2003 Annual Report filed on Form 8-K with the Securities and Exchange Commission on December 6, 2004, and (2) the balance sheet of Enterprise Products GP, LLC as of December 31, 2003, incorporated in this prospectus supplement by reference from Exhibit 99.1 to Enterprise Products Partners L.P.’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 22, 2004, have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports, which are incorporated herein by reference (each such report expresses an unqualified opinion and the report for Enterprise Products Partners L.P. includes an explanatory paragraph referring to a change in method of accounting for goodwill in 2002 and derivative instruments in 2001 as discussed in Notes 8 and 1, respectively, to Enterprise Products Partners L.P.’s consolidated financial statements), and have been so incorporated in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

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      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”) all incorporated in this prospectus supplement by reference to Enterprise Products Partners L.P.’s Current Reports on Form 8-K dated April 20, 2004 for (1) and (2) and April 16, 2004 for (3), have been so incorporated 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 derived from the report of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists, with respect to GulfTerra’s estimated oil and natural gas reserves incorporated in this prospectus supplement and accompanying base prospectuses by reference to our Current Report on Form 8-K dated April 20, 2004 has been so incorporated in reliance on the authority of said firm as experts with respect to such matters contained in their report.

INCORPORATION OF DOCUMENTS BY REFERENCE

      The Commission allows us to incorporate by reference into this prospectus supplement and the accompanying prospectus the information we file with it, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is considered to be part of this prospectus supplement and the accompanying prospectus, and later information that we file with the Commission will automatically update and supersede this information. We incorporate by reference the documents listed below and any future filings we make with the Commission under section 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 until our offering is completed (other than information furnished under Items 2.02, 7.01, 9 or 12 of any Form 8-K that is listed below or is filed in the future and which is not deemed filed under the Exchange Act):

  •  Our Annual Report on Form 10-K for the year ended December 31, 2003 except for Items 1, 2, 7 and 8, which have been superseded by the Current Report on Form 8-K filed with the Commission on December 6, 2004, Commission File No. 1-14323;
 
  •  Quarterly Reports on Form 10-Q for the quarters ended March 31, 2004, June 30, 2004 and September 30, 2004, Commission File Nos. 1-14323;
 
  •  Current Reports on Form 8-K filed with the Commission on December 15, 2003, January 6, 2004, February 10, 2004, March 22, 2004, April 16, 2004, April 20, 2004, April 21, 2004, April 26, 2004, April 27, 2004, May 3, 2004, July 29, 2004, August 2, 2004, August 5, 2004, August 11, 2004, August 30, 2004, September 1, 2004, September 7, 2004, September 8, 2004, September 14, 2004, September 17, 2004, September 21, 2004, September 27, 2004, September 28, 2004, October 1, 2004, October 6, 2004, October 27, 2004, December 6, 2004, December 15, 2004, January 4, 2005 and January 18, 2005, Commission File Nos. 1-14323;
 
  •  Current Report on Form 8-K filed with the Commission on June 16, 2004, as amended by the Current Report on Form 8-K/ A (Amendment No. 1) filed with the Commission on August 4, 2004, Commission File Nos. 1-14323;
 
  •  Current Report on Form 8-K filed with the Commission on August 2, 2004, as amended by the Current Report on Form 8-K/ A (Amendment No. 1) filed with the Commission on August 5, 2004, Commission File Nos. 1-14323;

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  •  Current Report on Form 8-K filed with the Commission on September 30, 2004, as amended by the Current Reports on Form 8-K/ A filed with the Commission on October 5, 2004 (Amendment No. 1), October 18, 2004 (Amendment No. 2), December 3, 2004 (Amendment No. 3), December 6, 2004 (Amendment No. 4) and December 27, 2004 (Amendment No. 5), Commission File Nos. 1-14323; and
 
  •  Current Report on Form 8-K (containing the description of our common units, which description amends and restates the description of our common units contained in the Registration Statement on Form 8-A, initially filed with the Commission on July 21, 1998) filed with the Commission on February 10, 2004, Commission File No. 1-14323.

FORWARD-LOOKING STATEMENTS

      This prospectus supplement, the related prospectus and some of the documents we have incorporated herein and therein by reference contain 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. When used in this prospectus supplement, the accompanying 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 our products by the petrochemical, refining or heating industries;
 
  •  the effects of our debt level on our future financial and operating flexibility;
 
  •  a decline in the volumes of NGLs delivered by our facilities;
 
  •  the failure of our credit risk management efforts to adequately protect us against customer non-payment;
 
  •  terrorist attacks aimed at our facilities;
 
  •  the failure to successfully integrate our operations with GulfTerra’s or any other companies we acquire; and
 
  •  the failure to realize the anticipated cost savings, synergies and other benefits of our merger with GulfTerra.

      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 supplement and the accompanying prospectus.

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INDEX TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS

Enterprise Products Partners L.P. Unaudited Pro Forma Condensed Consolidated Financial Statements:

         
Introduction
    F-2  
Unaudited Pro Forma Condensed Statement of Consolidated Operations for the nine months ended September 30, 2004
    F-4  
Unaudited Pro Forma Condensed Statement of Consolidated Operations for the year ended December 31, 2003
    F-5  
Unaudited Pro Forma Condensed Consolidated Balance Sheet at September 30, 2004
    F-6  
Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements
    F-7  

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Introduction

      The following unaudited pro forma condensed consolidated financial statements have been prepared to assist in the analysis of the financial effects of the transactions noted below. Unless the context requires otherwise, for purposes of this pro forma presentation, references to “we,” “our,” “us,” “the Company” or “Enterprise” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. References to “Operating Partnership” are intended to mean the consolidated business and operations of our primary operating subsidiary, Enterprise Products Operating L.P. 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.

      The unaudited pro forma condensed consolidated financial statements give effect to the following transactions:

  •  The completion of Enterprise’s merger with GulfTerra and the related transactions on September 30, 2004 (the “GulfTerra Merger Transactions”). The GulfTerra Merger Transactions took place in three steps as described on page F-8.
 
  •  The issuance by our Operating Partnership of $2 billion of senior unsecured notes on October 4, 2004. The net proceeds from this offering were used to reduce debt amounts outstanding under our $2.25 billion 364-Day Acquisition Revolving Credit Facility that was used to fund a portion of the purchase price at the closing of the GulfTerra Merger Transactions on September 30, 2004.
 
  •  The completion on October 5, 2004 of our 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 in cash borrowed under our $2.25 billion 364-Day Acquisition Revolving Credit Facility, which was placed in escrow on September 30, 2004.
 
  •  The public sale of 17,250,000 common units in both May 2004 and August 2004 by Enterprise. In addition, Enterprise issued a total of 5,183,591 common units in connection with its distribution reinvestment plan (“DRIP”) during the first eleven months of 2004 (2,199,350 common units were issued in November 2004).
 
  •  The conversion of the remaining outstanding 80 Series F2 convertible units, which were originally issued by GulfTerra, into 1,950,317 Enterprise common units in October and November 2004.

      The unaudited pro forma as adjusted condensed consolidated financial statements also give effect to the sale of 10,000,000 of our common units to the public at an assumed offering price of $27.28 per unit and the application of the net proceeds therefrom as described in Note (s) on page F-17.

      The unaudited pro forma condensed statements of consolidated operations for the nine months ended September 30, 2004 and the year ended December 31, 2003 assume the pro forma transactions noted above occurred on January 1, 2003 (to the extent not already reflected in the historical statements of consolidated operations). The unaudited pro forma condensed consolidated balance sheet shows the financial effects of the pro forma transactions as if they had occurred on September 30, 2004 (to the extent not already recorded in the historical balance sheet).

      Dollar amounts presented in the tabular data within these pro forma condensed consolidated financial statements and footnotes are stated in millions of dollars, unless otherwise indicated.

      The unaudited pro forma condensed consolidated financial statements and related pro forma information are based on assumptions that Enterprise 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

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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 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 and with the historical consolidated financial statements and related notes of Enterprise included in its 2003 Annual Report filed on Form 8-K with the Securities and Exchange Commission (the “Commission”) on December 6, 2004 and its Quarterly Report on Form 10-Q for the three and nine months ended September 30, 2004.

      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 year ended December 31, 2003 and for the three and nine months ended September 30, 2004, contained in Enterprise’s Current Report on Form 8-K filed with the Commission on April 20, 2004 and Current Report on Form 8-K/ A (Amendment No. 5) filed with the Commission on December 27, 2004, respectively.

      The combined financial statements for the year ended December 31, 2003 of El Paso Hydrocarbons, L.P. and El Paso NGL Marketing Company, L.P. (collectively, the “South Texas midstream assets”) included herein are qualified in their entirety by reference to the historical combined financial statements and related notes of the South Texas midstream assets included in Enterprise’s Current Report on Form 8-K filed with the Commission on April 16, 2004. The combined financial statements of the South Texas midstream assets for the eight months ended August 31, 2004 included herein were derived from the historical accounts and records of these entities.

 
Divestiture of Assets Required for FTC Approval of the GulfTerra Merger Transactions

      In connection with the GulfTerra Merger Transactions, we are required under a consent decree published for comment by the FTC on September 30, 2004 to sell our 50% interest in an entity 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. The $37.2 million carrying value of this investment was classified under “Assets Held for Sale” on our Unaudited Condensed Consolidated Balance Sheet at September 30, 2004. Enterprise recognized approximately $3 million in equity earnings from this investment for both the nine months ended September 30, 2004 and the year ended December 31, 2003. We are required to sell this investment by March 31, 2005. We have entered into a contract with a third party to sell this investment. We expect this sale to occur in the first quarter of 2005. The sale requires Federal Trade Commission approval under the terms of the consent decree relating to the GulfTerra Merger Transactions and is subject to other customary closing conditions.

      We expect the proceeds from the sale of this investment will exceed the carrying value of this investment. For purposes of pro forma presentation, we have not estimated the proceeds from this sale and therefore, our pro forma statements of operations do not reflect any net gain or loss. In addition, our pro forma statements of operations do not reflect the removal of equity earnings from this investment due to the insignificant effect on the pro forma results of operations.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Nine Months Ended September 30, 2004
                                                             
South Texas Adjusted
Midstream Adjustments Enterprise
Enterprise GulfTerra Assets Pro Forma Enterprise Due to this Pro
Historical Historical Historical Adjustments Pro Forma Offering Forma







REVENUES
  $ 5,458.5     $ 676.7     $ 1,103.2     $ (426.6 )(m)   $ 6,752.4             $ 6,752.4  
                              (59.4 )(q)                        
COSTS AND EXPENSES
                                                       
Operating costs and expenses
    5,226.4       432.3       1,058.3       103.2 (k)     6,272.8               6,272.8  
                              (20.0 )(l)                        
                              (421.5 )(m)                        
                              (46.5 )(p)                        
                              (59.4 )(q)                        
Selling, general and administrative
    26.6                       46.5 (p)     73.1               73.1  
     
     
     
     
     
             
 
   
Total
    5,253.0       432.3       1,058.3       (397.7 )     6,345.9               6,345.9  
     
     
     
     
     
             
 
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES
    42.2                       (32.0 )(n)     17.8               17.8  
                              7.6 (p)                        
     
     
     
     
     
             
 
OPERATING INCOME
    247.7       244.4       44.9       (112.7 )     424.3               424.3  
     
     
     
     
     
             
 
OTHER INCOME (EXPENSE)
                                                       
Interest expense
    (96.9 )     (82.7 )             5.1 (a)     (186.2 )   $ 6.8 (s)     (179.4 )
                              (42.6 )(g)                        
                              (28.4 )(h)                        
                              3.0 (i)                        
                              56.3 (j)                        
Loss due to early redemptions of debt
            (16.3 )                     (16.3 )             (16.3 )
Earnings from unconsolidated affiliates
            7.6               (7.6 )(p)                        
Other, net
    0.9       0.5       (0.1 )     1.2 (o)     2.5               2.5  
     
     
     
     
     
     
     
 
   
Total
    (96.0 )     (90.9 )     (0.1 )     (13.0 )     (200.0 )     6.8       (193.2 )
     
     
     
     
     
     
     
 
PROVISION FOR INCOME TAXES
    (2.7 )                             (2.7 )             (2.7 )
MINORITY INTEREST
    (6.9 )     1.8                       (5.1 )             (5.1 )
     
     
     
     
     
     
     
 
INCOME FROM CONTINUING OPERATIONS
  $ 142.1     $ 155.3     $ 44.8     $ (125.7 )   $ 216.5     $ 6.8     $ 223.3  
     
     
     
     
     
     
     
 
INCOME ALLOCATION:
                                                       
 
Limited partners
  $ 120.2                             $ 181.8             $ 187.6  
     
                             
             
 
 
General partner
  $ 21.9                             $ 34.7             $ 35.7  
     
                             
             
 
BASIC EARNINGS PER UNIT:
                                                       
 
Number of units used in denominator
    232.7                       23.2 (a)     364.2       10.0 (s)     374.2  
     
                             
             
 
                              2.0 (b)                        
                              2.2 (c)                        
                              104.1 (f)                        
 
Income from continuing operations
  $ 0.52                             $ 0.50             $ 0.50  
     
                             
             
 
DILUTED EARNINGS PER UNIT:
                                                       
 
Number of units used in denominator
    233.2                       23.2 (a)     364.7       10.0 (s)     374.7  
     
                             
             
 
                              2.0 (b)                        
                              2.2 (c)                        
                              104.1 (f)                        
 
Income from continuing operations
  $ 0.52                             $ 0.50             $ 0.50  
     
                             
             
 

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED STATEMENT OF CONSOLIDATED OPERATIONS

For the Year Ended December 31, 2003
                                                             
South Texas
Midstream Adjustments Adjusted
Enterprise GulfTerra Assets Pro Forma Enterprise Due to this Enterprise
Historical Historical Historical Adjustments Pro Forma Offering Pro Forma







REVENUES
  $ 5,346.4     $ 871.5     $ 1,430.7     $ (431.9 )(m)   $ 7,153.0             $ 7,153.0  
                              (63.7 )(q)                        
COSTS AND EXPENSES
                                                       
Operating costs and expenses
    5,046.8       557.0       1,423.2       153.0 (k)     6,633.1               6,633.1  
                              (1.5 )(l)                        
                              (427.2 )(m)                        
                              (54.5 )(p)                        
                              (63.7 )(q)                        
Selling, general and administrative
    37.5                       54.5 (p)     92.0               92.0  
     
     
     
     
     
             
 
   
Total
    5,084.3       557.0       1,423.2       (339.4 )     6,725.1               6,725.1  
     
     
     
     
     
             
 
EQUITY IN INCOME (LOSS) OF UNCONSOLIDATED AFFILIATES
    (14.0 )                     11.4 (p)     (2.6 )             (2.6 )
     
     
     
     
     
             
 
OPERATING INCOME
    248.1       314.5       7.5       (144.8 )     425.3               425.3  
     
     
     
     
     
             
 
OTHER INCOME (EXPENSE)
                                                       
Interest expense
    (140.8 )     (127.8 )             16.0 (a)     (284.2 )   $ 9.1 (s)     (275.1 )
                              (10.5 )(e)                        
                              (62.3 )(g)                        
                              (37.7 )(h)                        
                              3.9 (i)                        
                              75.0 (j)                        
Loss due to early redemptions of debt
            (36.9 )                     (36.9 )             (36.9 )
Earnings from unconsolidated affiliates
            11.4               (11.4 )(p)                        
Other, net
    6.4       1.1       0.1       0.8 (o)     8.4               8.4  
     
     
     
     
     
     
     
 
   
Total
    (134.4 )     (152.2 )     0.1       (26.2 )     (312.7 )     9.1       (303.6 )
     
     
     
     
     
     
     
 
PROVISION FOR INCOME TAXES
    (5.3 )                             (5.3 )             (5.3 )
MINORITY INTEREST
    (3.9 )     (0.9 )             0.9 (d)     (3.9 )             (3.9 )
     
     
     
     
     
     
     
 
INCOME FROM CONTINUING OPERATIONS
  $ 104.5     $ 161.4     $ 7.6     $ (170.1 )   $ 103.4     $ 9.1     $ 112.5  
     
     
     
     
     
     
     
 
INCOME ALLOCATION:
                                                       
 
Limited partners
  $ 83.8                             $ 67.1             $ 75.1  
     
                             
             
 
 
General partner
  $ 20.7                             $ 36.3             $ 37.4  
     
                             
             
 
BASIC EARNINGS PER UNIT:
                                                       
 
Number of units used in denominator
    199.9                       37.5 (a)     350.3       10.0 (s)     360.3  
     
                             
             
 
                              2.0 (b)                        
                              2.2 (c)                        
                              4.2 (e)                        
                              104.5 (f)                        
 
Income from continuing operations
  $ 0.42                             $ 0.19             $ 0.21  
     
                             
             
 
DILUTED EARNINGS PER UNIT:
                                                       
 
Number of units used in denominator
    206.4                       37.5 (a)     356.8       10.0 (s)     366.8  
     
                             
             
 
                              2.0 (b)                        
                              2.2 (c)                        
                              4.2 (e)                        
                              104.5 (f)                        
 
Income from continuing operations
  $ 0.41                             $ 0.19             $ 0.20  
     
                             
             
 

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

September 30, 2004
                                             
Adjustments Adjusted
Enterprise Pro Forma Enterprise Due to this Enterprise
Historical Adjustments Pro Forma Offering Pro Forma





ASSETS
Current Assets
                                       
 
Cash and cash equivalents
  $ 146.6     $ 39.6 (b)   $ 234.0     $ 278.4 (s)   $ 234.0  
              49.3 (c)             (11.9 )(s)        
              1,984.5 (h)             (266.5 )(s)        
              (1,984.5 )(h)                        
              (1.5 )(r)                        
 
Restricted cash, including $1.1 billion held in escrow for tender offers
    1,116.9       (1,073.3 )(j)     43.6               43.6  
 
Accounts and notes receivable, net
    828.7       3.7 (r)     832.4               832.4  
 
Inventories
    327.0       1.9 (r)     328.9               328.9  
 
Assets held for sale
    37.2               37.2               37.2  
 
Other current assets
    72.3       (8.5 )(r)     63.8               63.8  
     
     
     
     
     
 
   
Total Current Assets
    2,528.7       (988.8 )     1,539.9             1,539.9  
Property, plant and equipment, net
    7,723.7       (10.4 )(r)     7,713.3               7,713.3  
Investments in and Advances to Unconsolidated Affiliates
    464.3       (6.6 )(r)     457.7               457.7  
Intangible Assets, net
    961.9       29.5 (r)     991.4               991.4  
Goodwill
    445.9       16.8 (r)     462.7               462.7  
Other Assets
    58.9               58.9               58.9  
     
     
     
     
     
 
   
Total Assets
  $ 12,183.4     $ (959.5 )   $ 11,223.9     $     $ 11,223.9  
     
     
     
     
     
 
LIABILITIES & PARTNERS’ EQUITY
Current Liabilities
                                       
 
Current maturities of debt
  $ 607.2             $ 607.2       (265.5 )(s)   $ 341.7  
 
Accounts payable
    107.7               107.7               107.7  
 
Accrued gas payables
    921.1     $ 11.2 (r)     932.3               932.3  
 
Other current liabilities
    180.1       (25.9 )(j)     162.5               162.5  
              8.3 (r)                        
     
     
     
     
     
 
   
Total Current Liabilities
    1,816.1       (6.4 )     1,809.7       (265.5 )     1,544.2  
Long-Term Debt
    4,972.2       1,984.5 (h)     3,924.8       (1.0 )(s)     3,923.8  
              (1,984.5 )(h)                        
              (1,047.4 )(j)                        
Other Long-Term Liabilities
    54.2       5.4 (r)     59.6               59.6  
Minority Interest
    61.3               61.3               61.3  
Commitments and Contingencies Partners’ Equity                                        
 
Limited Partners
    5,164.4       38.8 (b)     5,251.5       261.1 (s)     5,512.6  
              48.3 (c)                        
 
General Partner
    105.4       0.8 (b)     107.2       5.4 (s)     112.6  
              1.0 (c)                        
 
Accumulated other comprehensive income
    24.1               24.1               24.1  
 
Other
    (14.3 )             (14.3 )             (14.3 )
     
     
     
     
     
 
 
Total Combined Equity
    5,279.6       88.9       5,368.5       266.5       5,635.0  
     
     
     
     
     
 
   
Total Liabilities & Combined Equity
  $ 12,183.4     $ (959.5 )   $ 11,223.9     $     $ 11,223.9  
     
     
     
     
     
 

See Notes to Unaudited Pro Forma Condensed Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS 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; therefore, actual results could materially differ from the pro forma information. However, Enterprise believes the assumptions provide a reasonable basis for presenting the significant effects of the transactions noted herein. Enterprise 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

 
General

      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. Additionally, Enterprise completed certain other transactions related to the merger, including the contribution by Enterprise’s general partner (“Enterprise GP”) of a 50% membership interest in GulfTerra’s general partner (“GulfTerra GP”), which was acquired by Enterprise 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 paid or issued to complete the GulfTerra Merger Transactions was approximately $4 billion. These transactions were accounted for using purchase accounting.

      Our September 30, 2004 Unaudited Condensed Consolidated Balance Sheet reflects the GulfTerra merger. Since the GulfTerra Merger Transactions closed during the day of September 30, 2004, our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income do not include any earnings from GulfTerra due to the immateriality of the amounts. Pursuant to written agreements, the effective closing date of our purchase of the South Texas midstream assets was September 1, 2004. Our Unaudited Condensed Statements of Consolidated Operations and Comprehensive Income for the three and nine months ended September 30, 2004 include one month of results of operations from the South Texas midstream assets.

      As a result of the GulfTerra Merger Transactions, GulfTerra and GulfTerra GP became wholly-owned subsidiaries of Enterprise on September 30, 2004. On October 1, 2004, we contributed our ownership interests in GulfTerra and GulfTerra GP to our Operating Partnership, which resulted in GulfTerra and GulfTerra GP becoming wholly-owned subsidiaries of the Operating Partnership.

 
Overview of the GulfTerra Assets and the South Texas Midstream Assets

      GulfTerra owns or has interests in natural gas pipeline systems extending over 15,650 miles. These pipeline systems include natural gas gathering systems located onshore in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas and offshore in active drilling and development regions in the Gulf of Mexico. GulfTerra also owns interests in five natural gas processing and treating plants in New Mexico, Texas and Colorado.

      In addition, GulfTerra has interests in seven multi-purpose offshore hub platforms in the Gulf of Mexico, including the recently completed Marco Polo TLP. These platforms were specifically designed to be used as deepwater hubs and production handling and pipeline maintenance facilities. Many of GulfTerra’s offshore natural gas and oil pipelines utilize these platforms.

      GulfTerra also owns two salt dome natural gas storage facilities in Mississippi that are connected to five interstate pipeline systems, have a combined current working capacity of 13.5 billion cubic feet (“Bcf”) and are capable of delivering in excess of 1.2 Bcf per day of natural gas. In addition, GulfTerra has the exclusive right to use a natural gas storage facility in South Texas under an operating lease that expires in January 2008.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

This facility has a working gas capacity of 6.4 Bcf and a maximum withdrawal capacity of 0.8 Bcf per day of natural gas.

      In addition, GulfTerra owns interests in five offshore crude oil pipeline systems, which extend over 800 miles, including the recently completed 390-mile Cameron Highway oil pipeline. GulfTerra also owns over 1,000 miles of intrastate NGL pipelines and four NGL fractionation plants in Texas and a 3.3 million barrel (“MMBbl”) propane storage facility in Mississippi; and, owns or leases NGL storage facilities in Louisiana and Texas with aggregate capacity of approximately 21.3 MMBbls. GulfTerra also owns interests in four minor oil and natural gas producing properties located in the Gulf of Mexico offshore Louisiana.

      The South Texas midstream assets purchased from El Paso consist of nine natural gas processing plants with a combined capacity of 1.9 Bcf per day, a 294-mile natural gas gathering system, a natural gas treating facility with a capacity of 150 MMcf per day and a small NGL pipeline.

 
The GulfTerra Merger Transactions

      The GulfTerra Merger Transactions occurred in several interrelated steps as described below.

  •  Step One. On December 15, 2003, Enterprise purchased a 50% membership interest in GulfTerra GP from El Paso for $425 million in cash. GulfTerra GP owned a 1% general partner interest in GulfTerra. Prior to completion of the GulfTerra Merger Transactions, Enterprise 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 our pre-merger revolving credit facilities. This borrowed amount was fully repaid with the net proceeds from equity offerings completed during the first nine months of 2004.
 
  •  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 GulfTerra Merger Transactions included the following:

  •  Immediately prior to closing the GulfTerra merger, 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 us without the receipt of additional general partner interest, common units or other consideration. Enterprise GP borrowed the foregoing $370 million from Dan Duncan LLC (which owns a 4.505% membership interest in Enterprise GP), which obtained the funds from a loan from EPCO (which indirectly owns an 85.595% membership interest in Enterprise GP).
 
  •  Immediately prior to closing the GulfTerra merger, Enterprise 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 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, Enterprise acquired the South Texas midstream assets from El Paso for $155.3 million in cash, which was effective September 1, 2004 and is subject to post-closing adjustments.

      In connection with the closing of the GulfTerra Merger Transactions, on September 30, 2004, our Operating Partnership borrowed an aggregate of $2.8 billion under its 364-Day Acquisition Revolving Credit Facility and Multi-Year Revolving Credit Facility (collectively referred to as the “Merger Revolving Credit Facilities”) in order to fund its cash payment obligations under Step Two and Step Three of the GulfTerra

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Merger Transactions, including the tender offers for GulfTerra’s outstanding senior and senior subordinated notes.

      The total consideration paid or granted for the GulfTerra Merger Transactions is summarized below:

             
Step One transaction:
       
 
Cash payment by Enterprise to El Paso for initial 50% membership interest in GulfTerra GP (a non-voting interest) made in December 2003
  $ 425.0  
     
 
   
Total Step One consideration
    425.0  
     
 
Step Two transactions:
       
 
Cash payment by Enterprise to El Paso for 10,937,500 GulfTerra Series C units and 2,876,620 GulfTerra common units
    500.0  
 
Fair value of equity interests granted to acquire remaining 50% membership interest in GulfTerra GP (voting interest)(1)
    461.3  
 
Fair value of Enterprise common units issued in exchange for remaining GulfTerra common units
    2,445.4  
 
Fair value of other Enterprise equity interests granted for unit awards and Series F2 convertible units
    4.0  
 
Fair value of receivable from El Paso for transition support payments(2)
    (40.3 )
 
Transaction fees and other direct costs incurred by Enterprise as a result of the GulfTerra Merger Transactions(3)
    24.1  
     
 
   
Total Step Two consideration
    3,394.5  
     
 
   
Total Step One and Step Two consideration
    3,819.5  
     
 
Step Three transaction:
       
 
Purchase of South Texas midstream assets from El Paso
    155.3  
     
 
   
Total consideration for Steps One through Three
  $ 3,974.8  
     
 


(1)  This preliminary 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 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 GP granted to El Paso in this transaction from the 50% membership interest in GulfTerra GP that Enterprise GP received. The preliminary 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 to purchase its initial 50% non-voting membership interest in GulfTerra GP in December 2003.
 
(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 Transactions. 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 of September 30, 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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of “Prepaid and other current assets” and “Other assets” on our historical Unaudited Condensed Consolidated Balance Sheet as of September 30, 2004 presented herein.
 
(3)  As a result of the GulfTerra Merger Transactions, 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.

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 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 December 31, 2004. Subsequent to September 30, 2004, we made purchase price adjustments of $1.5 million related to additional transaction fees associated with the GulfTerra Merger Transactions. Additionally, we adjusted our initial preliminary purchase price allocation to property, plant and equipment, intangible assets, goodwill and other various assets and liabilities we assumed in the GulfTerra Merger Transactions. The subsequent adjustments are reflected as pro forma adjustments on our Unaudited Pro Forma Condensed Consolidated Balance Sheet at September 30, 2004. The fair value conclusions related to the GulfTerra Merger Transactions may be updated further when the underlying valuation study is finalized and we have completed our review of all other related information.

                               
GulfTerra Merger Transactions

Purchase of
Merger South Texas
with Midstream
GulfTerra Assets Total



Purchase price allocation:
                       
 
Assets acquired in business combination:
                       
   
Current assets, including cash of $40,453
  $ 202.3     $ 7.6     $ 209.9  
   
Property, plant and equipment, net
    4,579.7       121.5       4,701.2  
   
Investments in and advances to unconsolidated affiliates
    202.7               202.7  
   
Intangible assets
    705.5       29.1       734.6  
   
Other assets
    27.5               27.5  
     
     
     
 
     
Total assets acquired
    5,717.7       158.2       5,875.9  
     
     
     
 
 
Liabilities assumed in business combination:
                       
   
Current liabilities
    (215.0 )     (2.9 )     (217.9 )
   
Long-term debt, including current maturities(1)
    (2,015.6 )             (2,015.6 )
   
Other long-term liabilities
    (47.9 )             (47.9 )
     
     
     
 
     
Total liabilities assumed
    (2,278.5 )     (2.9 )     (2,281.4 )
     
     
     
 
     
Total assets acquired less liabilities assumed
    3,439.2       155.3       3,594.5  
     
Total consideration for Steps One through Three
    3,819.5       155.3       3,974.8  
     
     
     
 
 
Goodwill
  $ 380.3     $     $ 380.3  
     
     
     
 

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(1)  Represents GulfTerra’s outstanding senior and senior secured note obligations prior to the completion of Enterprise’s tender offers on October 5, 2004. This amount also includes GulfTerra’s outstanding obligations under its revolving credit facility and secured term loans prior to Enterprise’s repayment of these debt obligations, which occurred on the GulfTerra Merger Transactions closing date.

      As a result of the preliminary purchase price allocation for Step Two and Step Three of the GulfTerra Merger Transactions, we recorded $734.6 million of amortizable intangible assets, primarily those related to customer relationships and contracts. The remaining preliminary amount represents goodwill of $380.3 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 connections.

Pro Forma Adjustments

      The pro forma adjustments made to the historical financial statements of Enterprise, GulfTerra and the South Texas midstream assets are described as follows:

      (a) During the first nine months of 2004, Enterprise issued 37,484,241 common units in public sales of common units and in connection with its DRIP and related programs, which generated aggregate net proceeds of approximately $755.9 million. The issuance of common units was as follows:

  •  1,053,861 common units issued in February 2004 in connection with the DRIP and related programs. Including our general partner’s related 2% capital contribution, total net proceeds from this offering were $23.1 million. Enterprise used the net proceeds from this offering for general partnership purposes.
 
  •  17,250,000 common units sold to the public and 1,757,347 common units issued in connection with the DRIP and related programs in May 2004. Including our general partner’s related 2% capital contribution, total net proceeds from these offerings were $388.4 million. Enterprise used $353.1 million of the net proceeds from such public offering to repay its $225 million Interim Term Loan and to temporarily reduce borrowings outstanding under its then existing revolving credit facilities by approximately $130 million. Enterprise used the $35.3 million in net proceeds received in connection with its DRIP for general partnership purposes.
 
  •  17,250,000 common units sold to the public and 173,033 common units issued in connection with the DRIP and related programs in August 2004. Including our general partner’s related 2% capital contribution, total net proceeds from these offerings were $344.4 million. Enterprise used $210 million of the net proceeds from such public offering to temporarily reduce borrowings outstanding under its then existing revolving credit facilities and the remainder to fund its payment obligations to El Paso in connection with Step Two of the GulfTerra Merger Transactions.

      As a result of the February, May and August 2004 offerings described above, the weighted-average number of common units outstanding increased 23.2 million for the nine months ended September 30, 2004 and 37.5 million for the year ended December 31, 2003. Since the receipt of proceeds from these offerings and the related increases in partners’ equity are already reflected in Enterprise’s historical consolidated balance sheet at September 30, 2004, no pro forma adjustments to the balance sheet are necessary.

      As a result of the use of proceeds from these offerings, pro forma interest expense decreased $5.1 million for the nine months ended September 30, 2004 and $16.0 million for the year ended December 31, 2003. In calculating the pro forma adjustment to interest expense for the nine months ended September 30, 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. In calculating the pro forma adjustment to interest expense for the year ended December 31, 2003, we used a weighted-average estimated variable interest rate of 3.0% based on a combination of the 3.4% estimated variable

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

interest rate we are currently being charged on amounts borrowed under our Merger Revolving Credit Facilities and average historical variable interest rates of other debt obligations that would have been 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 nine months ended September 30, 2004 and $16.7 million for the year ended December 31, 2003.

      The pro forma adjustment to interest expense for the year ended December 31, 2003 also reflects the write-off of $1 million in prepaid debt issuance costs resulting from the repayment of Enterprise’s Interim Term Loan. The removal of the debt issuance costs is already reflected in Enterprise’s historical statement of consolidated operations for the nine months September 30, 2004; therefore, no pro forma adjustment is required for the interim period.

      (b) 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 Series F2 convertible unit — that had identical terms except for vesting and termination dates and the number of common units into which they could be converted upon payment of the calculated purchase price per common unit. Prior to the GulfTerra merger, all the Series F1 convertible units were converted to GulfTerra common units by the holder. As a result of the GulfTerra merger, Enterprise assumed GulfTerra’s obligation associated with the Series F2 convertible units. All Series F2 convertible units outstanding at the merger date were converted into rights to purchase Enterprise common units. The Series F2 units were convertible into up to $40 million of Enterprise common units.

      On October 29, 2004, 60 of the 80 outstanding Series F2 convertible units were converted into 1,458,434 Enterprise common units. On November 8, 2004, the remaining 20 outstanding Series F2 convertible units were converted into 491,883 Enterprise common units. As a result of these conversions, Enterprise received net proceeds of approximately $39.6 million, which includes the related 2% capital contributions made by Enterprise’s general partner. Enterprise used the net proceeds from these conversions for general partnership purposes. As a result of these transactions, the weighted-average number of common units outstanding increased 2 million for the nine months ended September 30, 2004 and the year ended December 31, 2003.

      (c) Reflects Enterprise’s November 2004 issuance of 2,199,350 Enterprise common units in connection with its DRIP and related programs. Including our general partner’s related 2% capital contribution, total net proceeds from this offering were $49.3 million. Enterprise used the net proceeds for general partnership purposes. As a result of this offering, the weighted-average number of common units outstanding increased 2.2 million for the nine months ended September 30, 2004 and the year ended December 31, 2003.

      (d) Reflects the pro forma adjustment to minority interest expense related to Enterprise’s restructuring of the ownership interest of its general partner from a 1% direct interest in Enterprise and a 1.0101% direct interest in the Operating Partnership to a 2% direct interest in Enterprise in December 2003. The pro forma adjustment removes $0.9 million in minority interest expense attributable to the general partner’s ownership interest in the earnings of the Operating Partnership during 2003. As a result of this adjustment, Enterprise’s allocation of earnings to its general partner increases by a similar amount.

      (e) Reflects the pro forma adjustment to interest expense related to the $425 million borrowed by Enterprise to finance its December 15, 2003 purchase of a 50% membership interest in GulfTerra’s general partner (Step One of the GulfTerra Merger Transactions). This transaction was financed by $225 million borrowed under Enterprise’s Interim Term Loan (which was repaid using proceeds from our May 2004 public offering of common units — see Note (a)) and $200 million borrowed under its then existing revolving credit facilities. The $425 million borrowed to complete Step One of the GulfTerra Merger Transactions was

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

subsequently reduced by $100 million using net proceeds from a private offering of 4,413,549 Class B special units to an affiliate of EPCO in December 2003.

      If this net borrowing of $325 million had occurred on January 1, 2003, pro forma interest expense for the year ended December 31, 2003 would have increased by $10.5 million. In calculating the pro forma adjustment to interest expense, we used an estimated variable interest rate of 3.4%, which approximates the interest rate we are currently being charged on amounts borrowed under our Merger Revolving Credit Facilities. If this estimated interest rate were 1/8% higher, the pro forma adjustment to interest expense would be $10.9 million.

      Enterprise’s September 30, 2004 historical consolidated balance sheet and statement of consolidated operations for the nine months ended September 30, 2004 already reflect the impact of such investment in GulfTerra GP; therefore, no pro forma adjustments are required. The pro forma effect of the December 2003 issuance of Class B special units on the weighted-average number of Enterprise units outstanding was an increase of 4.2 million units for the year ended December 31, 2003.

      (f) Reflects the pro forma adjustment to common units outstanding resulting from the issuance of 104,549,823 Enterprise common units in the exchange with GulfTerra’s common unitholders on September 30, 2004 under Step Two of the GulfTerra Merger Transactions. The pro forma effect of these new common units on the weighted-average number of Enterprise units outstanding is an increase of 104.1 million common units for the nine months ended September 30, 2004 and 104.5 million common units for the year ended December 31, 2003.

      (g) On September 30, 2004, Enterprise borrowed approximately $2.8 billion under its Merger Revolving Credit Facilities to (i) fund $655.3 million in 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 $42.6 million for the nine months ended September 30, 2004 and $62.3 million for the year ended December 31, 2003. In calculating the pro forma adjustment to interest expense, we used an estimated variable interest rate of 3.4%, which approximates the interest rate we are currently being charged on amounts borrowed under our Merger Revolving Credit Facilities. If this estimated interest rate were 1/8% higher, the pro forma adjustment to interest expense would be $45.0 million for the nine months ended September 30, 2004 and $65.5 million for the year ended December 31, 2003. The pro forma adjustment to interest expense also reflects the removal of historical interest expense amounts recorded by GulfTerra on its revolving credit facility and secured term loans of $22.5 million for the nine months ended September 30, 2004 and $24.7 million for the year ended December 31, 2003. Enterprise’s September 30, 2004 historical balance sheet already reflects these borrowings; therefore, no pro forma adjustment is required.

      (h) 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

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Revolving Credit Facilities. The fixed-interest rate, principal amount issued and net proceeds (before offering expenses) of each senior note in this offering were as follows:

                                 
Fixed Proceeds to
Interest Principal Bond Us, Before
Senior Note Issued Rate Amount Discount Expenses





Senior Notes E, due October 2007
    4.000%     $ 500.0     $ 2.1     $ 497.9  
Senior Notes F, due October 2009
    4.625%       500.0       4.4       495.6  
Senior Notes G, due October 2014
    5.600%       650.0       4.8       645.2  
Senior Notes H, due October 2034
    6.650%       350.0       4.2       345.8  
             
     
     
 
Totals
          $ 2,000.0     $ 15.5     $ 1,984.5  
             
     
     
 

      After giving effect to the application of proceeds to reduce principal amounts outstanding under our variable-rate Merger Revolving Credit Facilities, the pro forma adjustment to interest expense resulting from the issuance of these senior notes is $28.4 million for the nine months ended September 30, 2004 and $37.7 million for the year ended December 31, 2003. If the variable-rates used to calculate the reduction in interest expense associated with the repayment of amounts outstanding under the Merger Revolving Credit Facilities were 1/8% higher, the pro forma adjustment to interest expense would have been $26.6 million for the nine months ended September 30, 2004 and $35.2 million for the year ended December 31, 2003.

      The pro forma adjustments to Enterprise’s September 30, 2004 consolidated balance sheet reflect the issuance of these senior notes and the subsequent repayment of $2 billion in principal amounts outstanding under the Merger Revolving Credit Facilities.

      (i) 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 financing activities associated with closing the GulfTerra Merger Transactions. Our 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 (h)). Each of the forward starting swaps was designated as a cash flow hedge in accordance with applicable accounting guidance.

      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 was recorded in Accumulated Other Comprehensive Income and will be amortized 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 nine months ended September 30, 2004 and $3.9 million for the year ended December 31, 2003. No pro forma adjustment to the condensed consolidated balance sheet is required.

      (j) 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 cash held in escrow that was borrowed on September 30, 2004 under the Merger Revolving Credit Facilities. The following table shows the four GulfTerra senior debt obligations

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

affected, including the principal amount of each series of notes tendered, as well as the payment made by Enterprise to complete the tender offers.

                                   
Cash Payments Made by Enterprise
Principal
Amount Accrued Tender Total
Description Tendered Interest Price Price





8.50% Senior Subordinated Notes due 2010
(Represents 98.2% of principal amount outstanding)
  $ 212.1     $ 6.2     $ 246.4     $ 252.6  
10.625% Senior Subordinated Notes due 2012
(Represents 99.9% of principal amount outstanding)
    133.9       4.9       167.6       172.5  
8.50% Senior Subordinated Notes due 2011
(Represents 99.5% of principal amount outstanding)
    319.8       9.4       359.4       368.8  
6.25% Senior Notes due 2010
(Represents 99.7% of principal amount outstanding)
    249.3       5.4       274.0       279.4  
     
     
     
     
 
 
Totals
  $ 915.1     $ 25.9     $ 1,047.4     $ 1,073.3  
     
     
     
     
 

      The pro forma adjustments to Enterprise’s September 30, 2004 consolidated balance sheet reflect the use of $1.1 billion of restricted cash to complete the tender offers.

      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 nine months ended September 30, 2004 and $75 million for the year ended December 31, 2003.

      (k) 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 (see page F-10). 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’s new basis in such assets of approximately $4.7 billion.

      In addition, Enterprise recorded $734.6 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 related to the customer relationships, we used a pattern in which the economic benefits are consumed or otherwise used as associated with the resource bases (i.e., the oil and gas reserves associated with the intangible assets) from which these customers produce. For purposes of calculating pro forma amortization expense related to the storage contracts, we applied the straight-line method to the remainder of the respective contract terms, which we estimate could range from 2 to 18 years.

      Overall, the pro forma depreciation and amortization expense adjustment was $103.2 million for the nine months ended September 30, 2004 and $153.0 million for the year ended December 31, 2003, after taking into account the historical expense amounts recorded by GulfTerra and the South Texas midstream assets.

      (l) Reflects the pro forma adjustment to remove $20 million in merger-related expenses recorded by GulfTerra during the nine months ended September 30, 2004, including $0.4 million related to the amortization of unit options that were extinguished immediately prior to the GulfTerra merger. The pro forma adjustment for year ended December 31, 2003 reflects the removal of $1.5 million of amortization expense associated with the GulfTerra unit options.

      (m) In accordance with the purchase and sale agreement between Enterprise and El Paso for the South Texas midstream assets, El Paso will retain a number of natural gas liquids marketing contracts. Enterprise’s

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

pro forma condensed statement of consolidated operations for the nine months ended September 30, 2004 includes adjustments to remove $426.6 million of revenues and $421.5 million of operating costs and expenses associated with these retained contracts. Likewise, for the year ended December 31, 2003, Enterprise’s pro forma condensed statement of consolidated operations includes adjustments to remove $431.9 million of revenues and $427.2 million of operating costs and expenses.

      (n) After Step Two of the GulfTerra Merger Transactions was completed on September 30, 2004, the general partner of GulfTerra became a wholly-owned subsidiary of Enterprise. This pro forma adjustment reflects the replacement of equity earnings from the general partner of GulfTerra that Enterprise recorded under Step One of the merger with consolidated earnings from GulfTerra, as if Step Two had occurred on January 1, 2003. This adjustment required the removal of $32 million of equity earnings from the general partner of GulfTerra that Enterprise recorded during the nine months ended September 30, 2004. Since Enterprise’s equity in the earnings of GulfTerra GP was a loss of less than $0.1 million for December 2003, no pro forma adjustment was made for the 2003 period due to the insignificant nature of the amount. Enterprise acquired its initial 50% membership interest in the general partner of GulfTerra on December 15, 2003 under Step One of the GulfTerra Merger Transactions.

      (o) In connection with the GulfTerra Merger Transactions, Enterprise 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 Transactions. Our pro forma condensed statements of consolidated operations reflect $1.2 million and $0.8 million of imputed interest income that would have been recognized from this agreement during the nine months ended September 30, 2004 and the year ended December 31, 2003, respectively.

      (p) Reflects pro forma classification adjustments necessary to conform GulfTerra’s and the South Texas midstream assets’ historical condensed statements of consolidated operations to Enterprise’s 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 operating expenses to conform to Enterprise’s method of presentation. GulfTerra’s and the South Texas midstream assets’ general and administrative costs were $46.5 million for the nine months ended September 30, 2004 and $54.5 million for the year ended December 31, 2003.
 
  •  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’s presentation of such earnings. As a result of this reclassification, GulfTerra’s operating income increased by $7.6 million for the nine months ended September 30, 2004 and by $11.4 million for the year ended December 31, 2003. Enterprise’s equity investments with industry partners are a vital component of its business strategy. Such investments are a means by which Enterprise 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 to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what Enterprise could accomplish on a stand-alone basis. Many of these equity investments perform supporting or complementary roles to Enterprise’s other business operations. Based on information provided to Enterprise by GulfTerra, the relationship between GulfTerra and its equity investees is similar.

      (q) Reflects the pro forma elimination of significant revenues and expenses between Enterprise, GulfTerra and the South Texas midstream assets as appropriate in consolidation. Upon completion of the GulfTerra Merger Transactions, GulfTerra and the South Texas midstream assets became wholly-owned subsidiaries of Enterprise.

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ENTERPRISE PRODUCTS PARTNERS L.P.

NOTES TO UNAUDITED PRO FORMA CONDENSED

CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

      Additionally, we agreed in the merger agreement with GulfTerra, subject to the terms of our partnership agreement, to increase the quarterly cash distribution for the quarterly distribution date immediately following the closing of the merger to at least $0.395 per unit, or $1.58 per common unit on an annualized basis. The increase in our quarterly cash distribution commenced with the distribution paid with respect to the third quarter of 2004.

      (r) Reflects subsequent purchase price adjustments and purchase price allocations associated with the GulfTerra Merger Transactions since September 30, 2004.

      (s) Reflects the sale in this offering of 10,000,000 Enterprise common units at an assumed offering price of $27.28 per unit in February 2005. Total net proceeds from this sale are expected to be approximately $266.5 million after deducting applicable underwriting discounts, commissions and offering expenses of $11.9 million. Included in the total net proceeds of $266.5 million is a net capital contribution made by the general partner of Enterprise of $5.4 million to maintain its 2% general partner interest in Enterprise, after deducting the general partner’s share of the underwriting discounts, commissions and offering expenses. For pro forma purposes, the net proceeds from this equity offering, including Enterprise’s general partner’s net capital contribution, will be used to reduce debt outstanding under the Merger Revolving Credit Facilities.

      As a result of our pro forma application of proceeds from this offering to reduce debt outstanding, pro forma interest expense will decrease by $6.8 million and $9.1 million for the nine months ended September 30, 2004 and year ended December 31, 2003 and, respectively. If the variable rates used to calculate the reduction in interest expense associated with the repayment of amounts outstanding under the Merger Revolving Credit Facilities were 1/8% higher, the pro forma adjustment to interest expense would have been $7 million for the nine months ended September 30, 2004 and $9.4 million for the year ended December 31, 2003.

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PROSPECTUS

(ENTERPRISE PRODUCTS PARTNERS L.P. LOGO)

$1,500,000,000
Enterprise Products Partners L.P.
Enterprise Products Operating L.P.


COMMON UNITS

DEBT SECURITIES


        We may offer the following securities under this prospectus:

  •  common units representing limited partner interests in Enterprise Products Partners L.P.; and
 
  •  debt securities of Enterprise Products Operating L.P., which will be guaranteed by its parent company, Enterprise Products Partners L.P.

      This prospectus provides you with a general description of the securities we may offer. Each time we sell securities we will provide a prospectus supplement that will contain specific information about the terms of that offering. The prospectus supplement may also add, update or change information contained in this prospectus. You should read carefully this prospectus and any prospectus supplement before you invest. You should also read the documents we have referred you to in the “Where You Can Find More Information” section of this prospectus for information on us and for our financial statements.

      In addition, common units may be offered from time to time by other holders thereof. Any selling unitholders will be identified, and the number of common units to be offered by them will be specified, in a prospectus supplement to this prospectus. We will not receive proceeds of any sale of shares by any such selling unitholders.

      Our common units are listed on the New York Stock Exchange under the trading symbol “EPD.”


      Unless otherwise specified in a prospectus supplement, the senior debt securities, when issued, will be unsecured and will rank equally with our other unsecured and unsubordinated indebtedness. The subordinated debt securities, when issued, will be subordinated in right of payment to our senior debt.

      Limited partnerships are inherently different from corporations. You should review carefully “Risk Factors” beginning on page 2 for a discussion of important risks you should consider before investing on our securities.

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

      This prospectus may not be used to consummate sales of securities unless accompanied by a prospectus supplement.


The date of this prospectus is April 21, 2003.


Table of Contents

TABLE OF CONTENTS

             
Page

ABOUT THIS PROSPECTUS
    iii  
OUR COMPANY
    1  
RISK FACTORS
    2  
 
Risks Related to Our Business
    2  
   
We have significant leverage that may restrict our future financial and operating flexibility
    2  
   
A decrease in the difference between NGL product prices and natural gas prices results in lower margins on volumes processed, which would adversely affect our profitability
    2  
   
A reduction in demand for our products by the petrochemical, refining or heating industries, could adversely affect our results of operations
    3  
   
A decline in the volume of NGLs delivered to our facilities could adversely affect our results of operations
    3  
   
Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment
    4  
   
Acquisitions and expansions may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing our risks of being unable to effectively integrate these new operations
    4  
   
Terrorist attacks aimed at our facilities could adversely affect our business
    4  
 
Risks Related to Our Common Units as a Result of Our Partnership Structure
    4  
   
We may not have sufficient cash from operations to pay distributions at the current level following establishment of cash reserves and payments of fees and expenses, including payments to our general partner
    4  
   
Cost reimbursements due our general partner may be substantial and will reduce our cash available for distribution to holders of common units
    5  
   
Our general partner and its affiliates have limited fiduciary responsibilities and conflicts of interest with respect to our partnership
    5  
   
Even if unitholders are dissatisfied, they cannot easily remove our general partner
    6  
   
If our general partner is removed without cause during the subordination period, your distribution and liquidation preference over the subordinated units will be prematurely eliminated
    6  
   
We may issue additional common units without the approval of common unitholders, which would dilute their existing ownership interests
    6  
   
Our general partner has a limited call right that may require common unitholders to sell their units at an undesirable time or price
    7  
   
Common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business
    7  
 
Tax Risks to Common Unitholders
    7  
   
The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to common unitholders
    8  
   
A successful IRS contest of the federal income tax positions we take may adversely impact the market for common units, and the costs of any contests will be borne by our unitholders and our general partner
    8  
   
Common unitholders may be required to pay taxes even if they do not receive any cash distributions
    8  
   
Tax gain or loss on disposition of common units could be different than expected
    8  
   
Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them
    9  
   
We are registered as a tax shelter. This may increase the risk of an IRS audit of us or a unitholder
    9  
   
We will treat each purchaser of common 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 common units
    9  
   
Common unitholders will likely be subject to state and local taxes in states where they do not live as a result of investment in our common units
    9  
USE OF PROCEEDS
    10  
RATIO OF EARNINGS TO FIXED CHARGES
    10  

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Page

DESCRIPTION OF DEBT SECURITIES
    11  
 
General
    11  
 
Guarantee
    12  
 
Certain Covenants
    12  
 
Events of Default
    16  
 
Amendments and Waivers
    17  
 
Defeasance
    19  
 
Subordination
    19  
 
Book-Entry System
    21  
 
Limitations on Issuance of Bearer Securities
    22  
 
No Recourse Against General Partner
    23  
 
Concerning the Trustee
    23  
 
Governing Law
    24  
DESCRIPTION OF OUR COMMON UNITS
    25  
 
Meetings/Voting
    25  
 
Status as Limited Partner or Assignee
    25  
 
Limited Liability
    25  
 
Reports and Records
    26  
 
Class A Special Units
    26  
CASH DISTRIBUTION POLICY
    27  
 
Distributions of Available Cash
    27  
 
Operating Surplus and Capital Surplus
    27  
 
Subordination Period
    28  
 
Distributions of Available Cash from Operating Surplus During the Subordination Period
    29  
 
Distributions of Available Cash from Operating Surplus After Subordination Period
    30  
 
Incentive Distributions
    30  
 
Distributions from Capital Surplus
    30  
 
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
    31  
 
Distributions of Cash upon Liquidation
    31  
DESCRIPTION OF OUR PARTNERSHIP AGREEMENT
    34  
 
Purpose
    34  
 
Power of Attorney
    34  
 
Reimbursements of Our General Partner
    34  
 
Issuance of Additional Securities
    34  
 
Amendments to Our Partnership Agreement
    35  
 
Withdrawal or Removal of Our General Partner
    36  
 
Liquidation and Distribution of Proceeds
    36  
 
Change of Management Provisions
    37  
 
Limited Call Right
    37  
 
Indemnification
    37  
 
Registration Rights
    38  
TAX CONSEQUENCES
    39  
 
Partnership Status
    39  
 
Limited Partner Status
    40  
 
Tax Consequences of Unit Ownership
    41  
 
Tax Treatment of Operations
    45  
 
Disposition of Common Units
    46  
 
Uniformity of Units
    48  
 
Tax-Exempt Organizations and Other Investors
    48  
 
Administrative Matters
    49  
 
State, Local and Other Tax Considerations
    51  
 
Tax Consequences of Ownership of Debt Securities
    51  
SELLING UNITHOLDERS
    52  
PLAN OF DISTRIBUTION
    52  
 
Distribution by Selling Unitholders
    53  
WHERE YOU CAN FIND MORE INFORMATION
    53  
FORWARD-LOOKING STATEMENTS
    54  
LEGAL MATTERS
    54  
EXPERTS
    54  

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      You should rely only on the information contained or incorporated by reference in this prospectus or any prospectus supplement. We 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. You should not assume that the information incorporated by reference or provided in this prospectus or any prospectus supplement is accurate as of any date other than the date on the front of each document.

      In this prospectus, the terms “we,” “us” and “our” refer to Enterprise Products Partners L.P. and Enterprise Products Operating L.P. and their subsidiaries, unless otherwise indicated or the context requires otherwise.

ABOUT THIS PROSPECTUS

      This prospectus is part of a registration statement that we file with the Securities and Exchange Commission (the “Commission”) using a “shelf” registration process. Under this shelf process, we may offer from time to time up to $1,500,000,000 of our securities. Each time we offer securities, we will provide you with a prospectus supplement that will describe, among other things, the specific amounts and prices of the securities being offered and the terms of the offering. The prospectus supplement may also add, update or change information contained in this prospectus. Any statement that we make in this prospectus will be modified or superseded by any inconsistent statement made by us in a prospectus supplement. Therefore, you should read this prospectus and any attached prospectus supplement before you invest in our securities.

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OUR COMPANY

      We are a publicly traded limited partnership that was formed in April 1998 to acquire, own, and operate all of the NGL processing and distribution assets of Enterprise Products Company, or EPCO. We conduct all of our business through our 99% owned subsidiary, Enterprise Products Operating L.P., our “Operating Partnership” and its subsidiaries and joint ventures. Our general partner, Enterprise Products GP, LLC, owns a 1.0% interest in us and a 1.0101% interest in our Operating Partnership.

      We are a leading North American midstream energy company that provides a wide range of services to producers and consumers of natural gas and natural gas liquids, or NGLs. 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 and industrial fuels. Our asset platform creates the only integrated natural gas and NGL transportation, fractionation, processing, storage and import/export network in North America. We provide integrated services to our customers and generate fee-based cash flow from multiple sources along our natural gas and NGL “value chain.” Our services include the:

  •  gathering and transmission of raw natural gas from both onshore and offshore Gulf of Mexico developments;
 
  •  processing of raw natural gas into a marketable product that meets industry quality specifications by removing mixed NGLs and impurities;
 
  •  purchase and transportation of natural gas for delivery to our industrial, utility and municipal customers;
 
  •  transportation of mixed NGLs to fractionation facilities by pipeline;
 
  •  fractionation, or separation, of mixed NGLs produced as by-products of crude oil refining and natural gas production into component NGL products: ethane, propane, isobutane, normal butane and natural gasoline;
 
  •  transportation of NGL products to end-users by pipeline, railcar and truck;
 
  •  import and export of NGL products and petrochemical products through our dock facilities;
 
  •  fractionation of refinery-sourced propane/propylene mix into high purity propylene, propane and mixed butane;
 
  •  transportation of high purity propylene to end-users by pipeline;
 
  •  storage of natural gas, mixed NGLs, NGL products and petrochemical products;
 
  •  conversion of normal butane to isobutane through the process of isomerization;
 
  •  production of high-octane additives for motor gasoline from isobutane; and
 
  •  sale of NGL and petrochemical products we produce and/or purchase for resale on a merchant basis.

      Certain of our facilities are owned jointly by us and other industry partners, either through co-ownership arrangements or joint ventures. Some of our jointly owned facilities are operated by other owners.

      We do not have any employees. All of our management, administrative and operating functions are performed by employees of EPCO, our ultimate parent company, pursuant to the EPCO Agreement. For a discussion of the EPCO Agreement, please read Item 13 of our Annual Report on Form 10-K.

      Our principal executive offices are located at 2727 North Loop West, Houston, Texas 77008-1038, and our telephone number is (713) 880-6500.

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RISK FACTORS

      An investment in our securities involves risks. You should consider carefully the following risk factors, together with all of the other information included in, or incorporated by reference into, this prospectus and any prospectus supplement in evaluating an investment in our securities. This prospectus also contains forward-looking statements that involve risks and uncertainties. Please read “Forward-Looking Statements.” Our actual results could differ materially from those anticipated in the forward-looking statements as a result of certain factors, including the risks described below and elsewhere in this prospectus. If any of these risks occur, our business, financial condition or results of operation could be adversely affected.

Risks Related to Our Business

We have significant leverage that may restrict our future financial and operating flexibility.

      Our leverage is significant in relation to our partners’ capital. At February 28, 2003, our total outstanding debt, which represented approximately 58.0% of our total capitalization, was approximately $2.1 billion. As of January 31, 2003, we had $2.1 billion of senior indebtedness ranking equal in right of payment to all of our other senior indebtedness. As to the assets of our subsidiary, Seminole Pipeline Company, this $2.1 billion in senior indebtedness is structurally subordinated and ranks junior in right of payment to $45 million of indebtedness of Seminole Pipeline Company.

      Debt service obligations, restrictive covenants and maturities resulting from this leverage may adversely affect our ability to finance future operations, pursue acquisitions and fund other capital needs, and may make our results of operations more susceptible to adverse economic or operating conditions. Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control.

      Our ability to access the capital markets for future offerings may be limited by adverse market conditions resulting from, among other things, general economic conditions, contingencies and uncertainties that are difficult to predict and beyond our control. If we are unable to access the capital markets for future offerings, we might be forced to seek extensions for some of our short-term maturities or to refinance some of our debt obligations through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which we might receive such extensions or additional bank credit could be more onerous than those contained in our existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility.

 
A decrease in the difference between NGL product prices and natural gas prices results in lower margins on volumes processed, which would adversely affect our profitability.

      The profitability of our operations depends upon the spread between NGL product prices and natural gas prices. NGL product prices and natural gas prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

  •  the level of domestic production;
 
  •  the availability of imported oil and gas
 
  •  actions taken by foreign oil and gas producing nations;
 
  •  the availability of transportation systems with adequate capacity;
 
  •  the availability of competitive fuels;
 
  •  fluctuating and seasonal demand for oil, gas and NGLs; and
 
  •  conservation and the extent of governmental regulation of production and the overall economic environment.

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      Our Processing segment is directly exposed to commodity price risks, as we take title to NGLs and are obligated under certain of our gas processing contracts to pay market value for the energy extracted from the natural gas stream. We are exposed to various risks, primarily that of commodity price fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. These pricing risks cannot be completely hedged or eliminated, and any attempt to hedge pricing risks may expose us to financial losses.

 
A reduction in demand for our products by the petrochemical, refining or heating industries, could adversely affect our results of operations.

      A reduction in demand for our 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 adversely affect our results of operations. For example:

        Ethane. If natural gas prices increase significantly in relation to ethane prices, it may be more profitable for natural gas processors 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 will cause the demand for propane to decline significantly and could cause a significant decline in the volumes of propane that we extract and transport.
 
        Isobutane. Any reduction in demand for motor gasoline in general or MTBE in particular may similarly 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, our operating margin from selling isobutane will be reduced.
 
        MTBE. A number of states have either banned or currently are considering legislation to ban MTBE. In addition, Congress is contemplating a federal ban on MTBE, and several oil companies have taken an early initiative to phase out the production of MTBE. If MTBE is banned or if its use is significantly limited, the revenues and equity earnings we record may be materially reduced or eliminated. For additional information regarding MTBE, please read “Business and Properties — Regulation and Environmental Matters — Impact of the Clean Air Act’s oxygenated fuels programs on our BEF investment” in our Annual Report on Form 10-K for the year ended December 31, 2002.
 
        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 we produce and expose our 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.

      Please read Items 1 and 2. “Business and Properties — The Company’s Operations” beginning on page 3 of our Annual Report on Form 10-K for a more detailed discussion of our operations.

 
A decline in the volume of NGLs delivered to our facilities could adversely affect our results of operations.

      Our profitability is materially impacted by the volume of NGLs processed at our facilities. A material decrease in natural gas production of crude oil refining, as a result of depressed commodity prices or otherwise, or a decrease in imports of mixed butanes, could result in a decline in the volume of NGLs delivered to our facilities for processing, thereby reducing revenue and operating income.

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Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

      As a result of business failures, revelations of material misrepresentations and related financial restatements by several large, well-known companies in various industries over the last year, there have been significant disruptions and extreme volatility in the financial markets and credit markets. Because of the credit intensive nature of the energy industry and troubling disclosures by some large, diversified energy companies, the energy industry has been especially impacted by these developments, with the rating agencies downgrading a number of large energy-related companies. Accordingly, in this environment we are exposed to an increased level of credit and performance risk with respect to our customers. If we fail to adequately assess the creditworthiness of existing or future customers, unanticipated deterioration in their creditworthiness could have an adverse impact on us.

 
Acquisitions and expansions may affect our business by substantially increasing the level of our indebtedness and contingent liabilities and increasing our risks of being unable to effectively integrate these new operations.

      From time to time, we evaluate and acquire assets and businesses that we believe complement our existing operations. We may encounter difficulties integrating these acquisitions with our existing b