UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004 or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     .

Commission file number: 1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.

(713) 880-6500
(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Securities to be registered pursuant to Section 12(g) of the Act: None.

          Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

          Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

          Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Yes þ No o

          The aggregate market value of the common units of Enterprise Products Partners L.P. (“EPD”) held by non-affiliates at June 30, 2004, based on the closing price of such equity securities in the daily composite list for transactions on the New York Stock Exchange on June 30, 2004, was approximately $2.3 billion. This figure excludes common units beneficially owned by Dan L. Duncan, trusts established for the benefit of Mr. Duncan’s family and directors and executive officers of Enterprise Products GP, LLC (our general partner) which are affiliates of EPD. There were 383,554,318 common units of EPD outstanding at March 15, 2005.

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

Glossary

     The following abbreviations, acronyms or terms used in this Form 10-K are defined below:

Glossary (Continued)

Glossary (continued)

Glossary (Continued)

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES.

          General

          We are a leading North American midstream energy company providing 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 that includes natural gas gathering, processing, transportation 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.

          On September 30, 2004, we completed the GulfTerra Merger and related transactions. For additional information regarding these events, please read “Recent Developments” beginning on page 2 of this annual report.

          As a result of the GulfTerra Merger, we have reorganized our business activities into four reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services and Petrochemical Services. Business segments are components of a business about which separate financial information is available. These components are regularly evaluated by the CEO of Enterprise GP in deciding how to allocate resources and in assessing performance. Generally, financial information is required to be reported on the basis that it is used internally for evaluating segment performance and deciding how to allocate resources to segments. For a narrative of our business and properties by segment, please read “The Company’s Operations” included within this Item 1 and 2 discussion.

          We were formed as a limited partnership in 1998 (NYSE symbol, “EPD”) to own and operate certain NGL related businesses of EPCO. We conduct substantially all of our business through our wholly owned Operating Partnership and its subsidiaries and joint ventures. We are owned 98% by our limited partners and 2% by our general partner, Enterprise GP. We and Enterprise GP are affiliates of EPCO, our ultimate parent company.

          We do not have any employees. All of our management, administrative and operating functions are performed by employees of EPCO, pursuant to the Administrative Services Agreement. For a discussion of the Administrative Services Agreement, please read Item 13 of this annual report. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Enterprise” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. and its subsidiaries. Our principal executive offices are located at 2727 North Loop West, Houston, Texas 77008 and our telephone number is (713) 880-6500.

          Cautionary Statement Regarding Forward-Looking Information and Risk Factors

          This annual report contains various forward-looking statements and information that are based on our beliefs and those of Enterprise GP, our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor Enterprise GP can give any assurances that such expectations will prove to be correct. Such statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please read the section titled “Risk Factors” included under Item 7 of this annual report.

1

          Business Strategy

          Our business strategy is to:

	•	capitalize on expected increases in natural gas, NGL and crude oil production resulting from development activities in the deepwater and continental shelf areas of the Gulf of Mexico and in the Rocky Mountain region;
	•	maintain a balanced and diversified portfolio of midstream energy assets and expand this asset base through organic development projects and accretive acquisitions of complementary midstream energy assets;
	•	share capital costs and risks through joint ventures or alliances with strategic partners that will provide the raw materials for these projects or purchase the project’s end products; and
	•	increase fee-based cash flows by investing in pipelines and other fee-based businesses and de-emphasize commodity-based activities.

          Recent Developments

          The following information summarizes our recent significant developments and transactions. For additional information regarding the capital projects described in this section, please read "Our Liquidity and Capital Resources — Capital Spending” included under Item 7 of this annual report.

          GulfTerra Merger

          On September 30, 2004, Enterprise and GulfTerra completed the merger of GulfTerra with a wholly owned subsidiary of Enterprise. Additionally, Enterprise completed certain other transactions related to the merger, including receipt of Enterprise GP’s contribution of a 50% membership interest in 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 was approximately $4 billion.

          As a result of the GulfTerra Merger, 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 our Operating Partnership.

          The GulfTerra Merger transactions

          The GulfTerra Merger occurred in several interrelated transactions 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, 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 amount was fully repaid with the net proceeds from equity offerings completed during 2004. For additional information regarding changes in our debt obligations since December 31, 2003, please see Note 9 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

•

Step Two. On September 30, 2004, the GulfTerra Merger was consummated and GulfTerra and GulfTerra GP became wholly owned subsidiaries of Enterprise. The GulfTerra Merger was accounted for using purchase accounting. Step Two of the GulfTerra Merger included the following transactions:

•

Immediately prior to closing the GulfTerra Merger, Enterprise 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

2

		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 membership interest in Enterprise GP), which obtained the funds from a loan from EPCO (which indirectly owns the remaining membership interests 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 certain South Texas midstream assets from El Paso for $155.3 million in cash. Pursuant to written agreements, our purchase of the South Texas midstream assets was effective September 1, 2004.

          In connection with the closing of the GulfTerra Merger, on September 30, 2004, our Operating Partnership borrowed an aggregate $2.8 billion under its new revolving credit facilities to fund its cash payment obligations under Step Two and Step Three of the GulfTerra Merger and related transactions, including the tender offers for GulfTerra’s outstanding senior and senior subordinated notes. For additional information regarding the GulfTerra Merger, please read Note 4 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          In connection with the GulfTerra Merger, we are required under a consent decree to sell our 50% interest in Starfish, which owns the Stingray natural gas pipeline and related gathering pipelines and dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana. In January 2005, we entered into a contract with a third party to sell this investment for approximately $41.2 million. We expect to close this sale during the first quarter of 2005. The sale requires FTC approval under the terms of the consent decree relating to the GulfTerra Merger and is subject to other customary closing conditions. Additionally, under the same consent decree, we were required to sell our undivided 50% interest in a Mississippi propane storage facility by December 31, 2004. We sold our interest in this facility during the fourth quarter of 2004.

          Acquisition of El Paso’s Interests in Enterprise and Enterprise GP by affiliates of EPCO

          In January 2005, an affiliate of EPCO acquired a 9.9% membership interest in Enterprise GP and 13,454,499 Enterprise common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and its affiliates own 100% of the membership interests of Enterprise GP and approximately 37.4% of our total outstanding common units. El Paso no longer owns any interest in us or Enterprise GP.

          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 (consisting of Anadarko, Dominion, Kerr-McGee, Spinnaker and Devon) for the dedication, processing and gathering of natural gas and condensate production from several natural gas fields in the Atwater Valley, DeSoto Canyon and Lloyd Ridge areas 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/d of natural gas. The platform, which is estimated to cost approximately $385 million, will be operated by Anadarko. Cal Dive is our 20% joint venture partner in the Independence Hub Platform project. Additionally, we will construct, own, and operate the 134-mile Independence Trail natural gas pipeline system, which will have a throughput capacity of approximately 850 MMcf/d of natural gas. The pipeline system, which is estimated to cost $280 million, will transport production from the Independence Hub platform to the Tennessee Gas Pipeline.

3

          Rocky Mountain NGL pipeline expansion and related NGL fractionation projects

          In January 2005, we started a project to expand our Mont Belvieu NGL fractionator to accommodate an expected increase in NGLs transported to Mont Belvieu from the Rocky Mountains area. Our Mont Belvieu facility’s current fractionation capacity is up to 210 MBPD of mixed NGLs. This project, which is expected to be completed in the first quarter of 2006 at an estimated total cost of $34.2 million, will increase total fractionation capacity at this facility by 15 MBPD and reduce its energy utilization costs. Additionally, we are reviewing a proposal to construct a new NGL fractionator at our Mont Belvieu complex that could add an additional 60 MBPD of fractionation capacity at this industry hub.

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

          Acquisition of Indian Springs natural gas gathering and processing assets from El Paso

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

          Non-Public Investigation by the Bureau of Competition of the Federal Trade Commission

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

          Available Information

          As an accelerated filer, we electronically file certain documents with the SEC. We file annual reports on Form 10-K; quarterly reports on Form 10-Q; current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto. From time-to-time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

          We provide electronic access to our periodic and current reports on our Internet website, www.epplp.com. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with, or furnish such materials to, the SEC. You may also contact our investor relations department at 713-880-6500 for paper copies of these reports free of charge.

4

THE COMPANY’S OPERATIONS

          As a result of the GulfTerra Merger, 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 according to the type of services rendered and products produced and/or sold. Each of these segments is more fully discussed in the following sections.

          We have revised our prior segment information in order to conform to the current business segment operations and presentation. For additional information regarding our business segments including revenues, gross operating margin (a non-GAAP financial measure) and assets, please read Note 19 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

OFFSHORE PIPELINES & SERVICES

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

          Offshore Natural Gas Pipelines

          Our offshore natural gas pipeline systems provide for the gathering and transmission of natural gas from natural gas production developments located in the Gulf of Mexico, primarily offshore Louisiana and Texas. Typically, these systems receive natural gas from producers, other pipelines and shippers through system interconnects and transport the natural gas to various downstream pipelines, including major interstate transmission pipelines that access multiple markets in the eastern half of the United States. In general, our offshore natural gas pipeline transportation agreements generate revenue for these systems based on transportation fees per unit of volume (typically in MMBtus) transported. These agreements tend to be long-term in nature, often involving life-of-reserve commitments with firm and interruptible components. Our offshore natural gas pipeline systems do not take title to the natural gas volumes they transport; rather, the shipper retains title and the associated commodity price risk.

          Within their market area, our offshore natural gas pipelines compete with other pipelines (both regulated and unregulated systems) primarily on the basis of price (in terms of transportation fees) and connections to downstream markets. These systems exhibit little to no effects of seasonality; however, they may be affected by weather events such as hurricanes and tropical storms in the Gulf of Mexico.

          Our offshore natural gas pipeline business is affected by natural gas exploration and production activities in these operating areas. If these exploration and production activities decline due to (i) the inability of producers to find economically viable reserves; (ii) a weakened domestic economy which lowers natural gas demand; or (iii) natural depletion of the gas production to which our natural gas pipelines are connected, then throughput volumes on these pipelines will decline, thereby affecting our earnings from these assets. We actively seek to offset the loss of volumes due to natural depletion by adding connections to new customers and gas production. In addition, we believe our offshore natural gas pipeline systems are positioned to benefit from expected increases in natural gas production from new deepwater developments in the Gulf of Mexico.

          Our offshore natural gas pipeline systems are subject to various types of regulation. For a discussion of the general impact of governmental regulation on our business, please read “The Company’s Operations — Regulation and Environmental Matters” beginning on page 34.

5

          The following table summarizes our primary offshore natural gas pipeline assets at March 1, 2005. Our ownership interest in each pipeline is held either through a consolidated subsidiary or indirectly through a company in which we have an investment accounted for under the equity method. For additional information regarding our equity method investments, please read Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          The 1,149 miles of offshore natural gas pipelines shown in the preceding table excludes the Stingray and Triton natural gas pipelines owned by Starfish. In connection with the GulfTerra Merger, we are required under a consent decree to sell our 50% interest in Starfish. In January 2005, we entered into a contract with a third party to sell this investment for approximately $42.1 million. We expect to close this sale during the first quarter of 2005. The sale requires FTC approval under the terms of the consent decree relating to the GulfTerra Merger and is subject to other customary closing conditions

          The following table shows the approximate capacity (on a net basis in accordance with our ownership interest) of each of our primary offshore natural gas pipeline systems and an estimate of capacity utilization for the periods in which we owned these assets.

          The following table reflects overall throughput rates of our offshore natural gas pipelines (on a net basis in accordance with our ownership interests) for the periods in which we owned them during 2004, 2003 and 2002.

6

          The throughput rate for 2004 increased as a result of offshore natural gas pipeline assets acquired in the GulfTerra Merger on September 30, 2004.

          The following is a brief description of each of our primary offshore natural gas pipeline assets, all of which we operate with the exception of the Manta Ray Gathering System, Nautilus System, Nemo Gathering System and certain components of the Green Canyon Laterals:

          Manta Ray Gathering System. The Manta Ray Gathering System consists of natural gas gathering pipelines and related equipment located in the Gulf of Mexico offshore Louisiana. The Manta Ray system transports natural gas from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of Mexico to numerous downstream pipelines, including our Nautilus pipeline.

          High Island Offshore System (“HIOS”). HIOS is an offshore natural gas transmission system that transports natural gas from producing fields located in the Galveston, Garden Banks, West Cameron, High Island, and East Breaks areas of the Gulf of Mexico to the ANR pipeline system, Tennessee Gas Pipeline and the U-T Offshore System.

          Viosca Knoll Gathering System. The Viosca Knoll Gathering System is a natural gas gathering system located off the coast of Louisiana that transports natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico to several major interstate pipelines, including the Tennessee Gas Pipeline, Columbia Gulf, Southern Natural, Transco and Destin pipelines.

          Green Canyon Laterals. The Green Canyon Laterals consist of 28 laterals, which are extensions of natural gas pipelines, located in the Gulf of Mexico offshore Texas and Louisiana. These laterals deliver natural gas to numerous downstream pipelines, including our HIOS system.

          Anaconda Gathering System. The Anaconda Gathering System is a natural gas gathering system that connects our Marco Polo tension-leg platform and ChevronTexaco and BHP’s Typhoon platform, both of which are located in the Green Canyon area of the Gulf of Mexico, to the ANR pipeline system.

          Nautilus System. The Nautilus System consists of a natural gas pipeline system located in the Gulf of Mexico offshore Louisiana. Currently, the primary source of natural gas throughput for the Nautilus system is volume originating from our Manta Ray system. Natural gas volumes transported by the Nautilus system are delivered to our Neptune gas plant for processing.

          East Breaks System. The East Breaks System is a natural gas gathering system that connects the Hoover-Diana deepwater platform, which is owned by affiliates of ExxonMobil and BP and located in Alaminos Canyon Block 25, to our HIOS natural gas pipeline system.

          Phoenix Gathering System. The Phoenix Gathering System is a natural gas gathering system, which commenced operations in July 2004, connecting Kerr-McGee and Devon’s Red Hawk platform located in the Garden Banks area of the Gulf of Mexico to the ANR pipeline system.

          Nemo Gathering System. The Nemo Gathering System is a natural gas gathering pipeline located offshore Louisiana that transports natural gas volumes from Shell’s Green Canyon developments to an interconnect with our Manta Ray Gathering System.

          Falcon Gas Pipeline. The Falcon Gas Pipeline is a natural gas pipeline located off the Texas coast that delivers Pioneer Natural Resources’ natural gas processed at our Falcon Nest platform to a connection with the Central Texas Gathering System located on the Brazos Addition Block 133 platform.

7

          Offshore Crude Oil Pipelines

          As a result of the GulfTerra Merger, we acquired interests in several offshore crude oil pipeline systems which are located in the vicinity of oil-producing areas in the Gulf of Mexico. Typically, these systems receive oil from offshore production developments, other pipelines or shippers through system interconnects and deliver the oil to either onshore locations or to other offshore interconnecting pipelines. In general, our oil pipeline systems generate revenue based on agreements resulting from purchasing and selling products at price differentials per unit of volume (typically in barrels) received. A substantial portion of the revenues generated by our oil pipeline systems are attributed to production from reserves committed under long-term contracts for the productive life of the relevant field or purchases and sales of crude oil with terms from two to twelve months. The rates we charge for our services are dependent on the volume of crude oil to be delivered and the amount and term of the reserve commitment by the customer.

          Cameron Highway’s, Poseidon’s and Typhoon’s agreements require the purchase of producer’s oil at the inlet of their pipelines for an index-based price, less a price differential. At the outlet of their pipelines, Cameron Highway, Poseidon and Typhoon sell the oil back to producers at the same index-based price. These transactions are recorded as net revenue.

          Our offshore oil pipeline systems were built as a result of the need for additional crude oil capacity to receive and deliver new deepwater oil production to shore. Our competition includes other oil pipeline systems, built, owned and operated by producers to handle their own production and, as capacity is available, production for others. Our oil pipelines compete for new production on the basis of geographic proximity to the production, cost of connection, available capacity, transportation fees and access to onshore markets. In addition, the ability of our pipelines to access future reserves will be subject to our ability, or the producer’s ability, to fund the significant capital expenditures required to connect to the new production. These pipeline systems exhibit little to no effects of seasonality; however, they may be affected by cyclical weather events such as hurricanes and tropical storms in the Gulf of Mexico.

          Our offshore oil pipeline business is affected by crude oil exploration and production activities in these operating areas. If these exploration and production activities decline due to (i) the inability of producers to find economically viable reserves; (ii) a weakened domestic economy which lowers crude oil demand; or (iii) natural depletion of the crude oil production to which our oil pipelines are connected, then throughput volumes on these pipelines will decline, thereby affecting our earnings from these assets. We actively seek to offset the loss of volumes due to natural depletion by adding connections to new customers and oil production.

          Our offshore crude oil pipeline systems are subject to various types of regulation. For a discussion of the general impact of governmental regulation on our business, please read “The Company’s Operations - Regulation and Environmental Matters” beginning on page 34.

          The following table summarizes our primary offshore oil pipeline assets at March 1, 2005. Our ownership interest in each pipeline is held either through a consolidated subsidiary or indirectly through a company in which we have an investment accounted for under the equity method. For additional information regarding our equity method investments, please read Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

8

          The following table shows the approximate capacity (on a net basis in accordance with our ownership interest) of each of our primary offshore crude oil pipeline systems and an estimate of capacity utilization for the three month period (October 2004 through December 2004) in which we owned these assets.

          The following table reflects overall throughput volumes of our offshore crude oil pipelines (on a net basis in accordance with our ownership interests) for the three-month period that we owned them during 2004 (October 2004 through September 2004).

          The following is a brief description of each of our primary offshore crude oil pipeline assets, all of which we operate:

          Cameron Highway Oil Pipeline. The Cameron Highway Oil Pipeline (“Cameron Highway”), which commenced operations during the first quarter of 2005, is designed to gather production from the deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in Port Arthur and Texas City, Texas.

          Cameron Highway is supported by life of lease dedications with BP, BHP Billiton 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 to purchase and sell its 50% share of crude oil production from the Holstein field. The Holstein field began producing in December 2004 and first production from the Mad Dog field commenced January 2005. Production from the Atlantis, Constitution and Ticonderoga fields is expected to begin in 2006.

          Poseidon System. The Poseidon System is a major offshore sour crude oil pipeline system that gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico to onshore locations at Houma, Louisiana. The Poseidon System includes the newly constructed Front Runner Oil Pipeline, which is a 36-mile crude oil pipeline that connects the Front Runner field located in Green Canyon Blocks 338 and 339 in the central Gulf of Mexico with Poseidon’s main pipeline at Ship Shoal Block 332. The Front Runner Oil Pipeline received its first volumes from the Front Runner field in January 2005.

          Allegheny Oil Pipeline. The Allegheny Oil Pipeline is an offshore crude oil pipeline system that connects the Allegheny and South Timbalier 316 platforms in the Green Canyon area of the Gulf of Mexico with our Poseidon System at the Ship Shoal 332 platform. Oil production from the Allegheny and South Timbalier 316 fields is committed to the Allegheny Oil Pipeline. In addition, the Allegheny Oil Pipeline receives crude oil production gathered from our Marco Polo Oil Pipeline.

          Marco Polo Oil Pipeline. The Marco Polo Oil Pipeline is a newly constructed crude oil gathering system which gathers crude oil from our Marco Polo tension-leg platform to an interconnect with our Allegheny Oil Pipeline in Green Canyon Block 164.

          Typhoon Oil Pipeline. The Typhoon Oil Pipeline is an offshore crude oil pipeline that connects ChevronTexaco and BHP’s Typhoon platform in the Green Canyon area of the Gulf of Mexico to Shell’s Boxer platform. The Shell Boxer platform provides access to our Poseidon System through a third-party pipeline.

9

          Tarantula Oil Pipeline. The Tarantula Oil Pipeline is a newly constructed oil pipeline that connects the Tarantula field located in South Timbalier Block 308 in the central Gulf of Mexico to our Poseidon System. The Tarantula Oil Pipeline received its first volumes from the Tarantula field in January 2005.

          Offshore Platforms

          As a result of the GulfTerra Merger, we acquired ownership interests in seven multi-purpose offshore hub platforms located in the Gulf of Mexico. Offshore platforms are critical components of the offshore infrastructure in the Gulf of Mexico, supporting drilling and production operations, and therefore play a key role in the overall development of offshore oil and natural gas reserves. Platforms are used to: (i) interconnect with the offshore pipeline grid; (ii) provide an efficient means to perform pipeline maintenance (iii) locate compression, separation, production handling and other facilities; (iv) conduct drilling operations during the initial development phase of an oil and natural gas property; and (v) process off-lease production.

          Our platforms generally earn revenues through demand fees and commodity charges. A demand fee is typically a fixed-fee charged to a customer using our platform services regardless of the volume the customer delivers to the platform. A commodity charge is typically a fixed fee per MMcf of natural gas or barrel of crude oil, whichever the case may be, multiplied by the volume delivered to the platform by the customer. Contracts for platform services often include both demand fees and commodity charges, but demand fees generally expire after a contractual fixed period of time.

          Offshore platforms are subject to similar competitive factors as our offshore natural gas and oil pipeline systems. These assets generally compete with other platform service providers on the basis of proximity and access to existing reserves and pipeline systems, as well as costs and rates. Furthermore, our competitors in this business may possess greater capital resources than we have. Our platforms exhibit little to no effects of seasonality; however, they may be affected by cyclical weather events such as hurricanes and tropical storms in the Gulf of Mexico.

          Our offshore platforms are affected by crude oil and natural gas exploration and production activities in these operating areas. If these exploration and production activities decline due to (i) the inability of producers to find economically viable reserves; (ii) a weakened domestic economy which lowers crude oil and natural gas demand; or (iii) natural depletion of the oil and gas fields to which they are connected, then processing volumes on these platforms will decline, thereby affecting our earnings from these assets. We actively seek to offset the loss of volumes due to natural depletion by adding connections to new customers and fields.

          Our offshore platforms are subject to various types of regulation. For a discussion of the general impact of governmental regulation on our business, please read “The Company’s Operations - Regulation and Environmental Matters” beginning on page 34.

          The following table summarizes our primary offshore platform assets at March 1, 2005. Our ownership interest in each platform is held either through a consolidated subsidiary or indirectly through a company in which we have an investment accounted for under the equity method. For additional information regarding our equity method investments, please read Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

10

          The following table shows the approximate platform processing capacity (on a net basis in accordance with our ownership interest) of our primary offshore platforms and an estimate of capacity utilization for the three month period (October 2004 through December 2004) in which we owned these assets. Ship Shoal 332 A and B and 331 are excluded from this table since their primary functions are to serve as junction platforms for pipeline interconnects.

          The following table reflects overall platform processing volumes of natural gas and crude oil of our offshore platforms (on a net basis in accordance with our ownership interest) for the three-month period that we owned them during 2004 (October 2004 through September 2004).

          The following is a brief description of each of our primary offshore platform assets, all of which we operate with the exception of the Marco Polo tension-leg platform and Ship Shoal 332 A, East Cameron 373 and Ship Shoal 331 platforms:

          Marco Polo. The Marco Polo tension-leg platform was installed in the first quarter of 2004 and commenced operations in July 2004. The Marco Polo tension-leg platform processes crude oil and natural gas from Anadarko’s Marco Polo field located in Green Canyon Block 608. Additionally, the Marco Polo tension-leg platform is expected to begin receiving production volumes from the K2 and K2 North fields during 2005.

          Anadarko has dedicated 69,120 acres of property to the Marco Polo tension-leg platform, including acreage underlying their Marco Polo field, for the life of the reserves. Additionally, Anadarko has contracted with the Marco Polo tension-leg platform for firm gross processing capacity of 100 MBPD of crude oil and 150 MMcf/d of natural gas. The remainder of the platform’s oil processing capacity is contracted to Anadarko’s partners in the K-2 field. We have certain rights to get capacity back to market to third parties, if it becomes available. Anadarko is operator of the Marco Polo tension-leg platform.

          Viosca Knoll 817. The Viosca Knoll 817 platform is centrally located on our Viosca Knoll Gathering System. This platform serves as a base for gathering deepwater production in the area, including ExxonMobil’s, Shell’s, and BP’s Ram Powell development. A 7,000 horsepower compressor on the platform facilitates deliveries from our Viosca Knoll Gathering System to multiple downstream interstate pipelines. The platform is also used as a base for crude oil and natural gas production from our Viosca Knoll Block 817 lease and Walter Oil and Gas’ Viosca Knoll 862 lease.

          Garden Banks 72. The Garden Banks 72 platform serves as a base for landing deepwater production from Newfield Exploration Inc.’s Garden Banks Block 161 development, LLOG Exploration Offshore’s Garden Banks Block 378 lease and Amerada Hess Corporation’s Garden Banks Block 158 lease. The platform is also used as a junction platform for our Cameron Highway Oil Pipeline.

          Ship Shoal 332 A and B. The Ship Shoal 332A platform serves as a junction platform for our Manta Ray and Nemo natural gas pipelines and our Poseidon and Allegheny oil pipelines. Enbridge operates the Ship Shoal 332A platform. The Ship Shoal 332B platform is connected to Ship Shoal 332A platform and is owned by Cameron Highway, our unconsolidated affiliate. The Ship Shoal 332B platform is a major junction platform for the Cameron

11

Highway Oil Pipeline and will also serve as the junction platform for the Constitution Oil Pipeline.

          East Cameron 373. The East Cameron 373 platform serves as the host for Kerr-McGee’s East Cameron Block 373 production and as the gathering site for production at Garden Banks Blocks 108, 152, 197, 200 and 201. Kerr-McGee operates the East Cameron 373 platform.

          Falcon Nest. The Falcon Nest platform processes natural gas from Pioneer Natural Resources Company’s Falcon, Harrier and Raptor fields. Pioneer has dedicated 69,120 acres of property to this platform for the life of the reserves.

          Ship Shoal 331. The Ship Shoal 331 platform is used by Maritech Resources, Inc. to support production operations.

          Major Construction Projects

          Independence Hub Platform and Independence Trail Pipeline System. In November 2004, we entered into an agreement with the Atwater Valley Producers Group for the dedication, processing and gathering of natural gas and condensate production from several natural gas fields in the Atwater Valley, DeSoto Canyon and Lloyd Ridge areas (collectively, the “anchor fields”) of the deepwater Gulf of Mexico. We will design, construct, and own Independence Hub, a 105-foot deep-draft, semi-submersible platform with a two-level production deck, which will be capable of processing 850 MMcf/d of natural gas. The platform, which is estimated to cost approximately $385 million, will be operated by Anadarko, and is designed to process production from its anchor fields and has excess payload capacity to support ten additional pipeline risers. In December 2004, we entered into an agreement with Cal Dive to sell them a 20% indirect interest in the Independence Hub platform. Under the terms of the agreement, we will have access to Cal Dive’s fleet of vessels, which will assist us in the construction of the Independence Hub platform and the related export pipeline.

          The Independence Hub platform will be located on Mississippi Canyon Block 920, in a water depth of 8,000 feet. This location was selected for the permanently anchored platform based on favorable seafloor conditions and proximity to the identified anchor fields. First production is expected in 2007. Under the terms of the agreement, the production fields served by the Independence Hub platform will include the dedicated anchor fields in addition to future discoveries on surrounding undeveloped blocks.

          Additionally, we will construct, own, and operate the 134-mile Independence Trail natural gas pipeline system, which will have a throughput capacity of approximately 850 MMcf/d of natural gas. The pipeline system, which is estimated to cost $280 million, will transport production from the Independence Hub platform to the Tennessee Gas Pipeline. We entered into an agreement with Tennessee Gas Pipeline under which they will pay us $15 million for contributions in aid of construction to connect the Independence Trail natural gas pipeline system to their pipeline system. In November 2004, Tennessee Gas Pipeline reimbursed us $7 million for construction costs incurred. The balance of $8 million would be reimbursed by Tennessee Gas Pipeline when additional costs are incurred and is contingent upon our completion of the Independence Trail project, which is expected during 2006.

          Constitution Gathering System. In July 2004, GulfTerra entered into a definitive agreement to construct, own, and operate oil and natural gas pipelines to provide production gathering services for the Constitution field, which is 100% owned by Kerr-McGee. The Constitution field is located at a depth of 5,300 feet in Green Canyon Blocks 679 and 680 in the Central Gulf of Mexico. The new $53.4 million natural gas pipeline will be a 32-mile, 16-inch pipeline with a transport capacity of up to 200 MMcf/d and will connect to our existing Anaconda Gathering System. The new $76.2 million oil pipeline will be a 70-mile, 16-inch pipeline with a minimum transport capacity of 80 MBPD that will connect with the Cameron Highway Oil Pipeline and Poseidon System at our Ship Shoal 332B platform. These pipelines are expected to start transporting volumes in the first half of 2006.

          Intangible Assets

          At December 31, 2004, the Offshore Pipelines & Services segment included $200 million of intangible assets primarily related to customer relationships. For information regarding our intangible assets, please read Note 8 of the Notes to Consolidated Financial Statements, which is included under Item 8 of this annual report.

12

ONSHORE NATURAL GAS PIPELINES & SERVICES

          We own or have interests in approximately 17,200 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. In addition, we own two salt dome natural gas storage facilities located in Mississippi, which are strategically located to serve the Northeast, Mid-Atlantic and Southeast domestic natural gas markets. This segment also includes leased natural gas storage facilities located in Texas and Louisiana.

          Onshore Natural Gas Pipelines

          Our onshore natural gas pipeline systems provide for the gathering and transmission of natural gas from onshore developments, such as the San Juan and Permian supply basins, or from offshore developments in the Gulf of Mexico, through connections with offshore pipelines. Typically, these systems receive natural gas from producers, other pipelines or shippers through system interconnects and redeliver the natural gas to processing facilities, local gas distribution companies, industrial customers or to other onshore pipelines. Generally, natural gas pipeline gathering or transportation agreements generate revenue for these systems based on a fee per unit of volume (generally in MMBtus) gathered or transported. Natural gas pipelines (such as our Acadian Gas and Alabama Intrastate systems) may also gather and purchase natural gas from producers and suppliers and resell such natural gas to customers such as electric utility companies, local natural gas distribution companies and industrial customers.

          Our Acadian Gas and Alabama Intrastate pipelines are exposed to commodity price risk to the extent they take title to natural gas volumes through certain of their contracts. In addition, our San Juan Gathering and Permian Basin pipeline systems provide aggregating and bundling services, in which we purchase and resell natural gas for certain small producers. Also, several of our gathering systems, while not providing marketing services, have some exposure to risks related to commodity prices through transportation arrangements with shippers. For example, over 95% of the volumes handled by the San Juan Gathering System are fee-based arrangements, 80% of which are calculated as a percentage of a regional price index for natural gas. We use commodity financial instruments from time to time to mitigate our exposure to risks related to commodity prices.

          Within their market areas, our onshore natural gas pipelines compete with other onshore natural gas pipelines on the basis of price (in terms of transportation fees and/or natural gas selling prices), service and flexibility. Our competitive position within the onshore market is enhanced by our longstanding relationships with customers and the limited number of delivery pipelines connected (or capable of being connected) to the customers we serve.

          Our onshore natural gas pipeline business is affected by natural gas exploration and production activities. If these exploration and production activities decline due to (i) the inability of producers to find economically viable reserves; (ii) a weakened domestic economy which lowers natural gas demand; or (iii) natural depletion of the gas production to which they are connected, then throughput volumes on these pipelines will decline, thereby affecting our earnings from these assets. We actively seek to offset the loss of volumes due to natural depletion by adding connections to new customers and gas production.

          Certain of our onshore natural gas pipelines (such as the Texas Intrastate System) are subject to regulation. For a discussion of the general impact of governmental regulation on our business, please read “The Company’s Operations - Regulation and Environmental Matters” beginning on page 34.

13

          The following table summarizes our primary onshore natural gas pipeline systems at March 1, 2005. Our ownership interest in each pipeline is held either through a consolidated subsidiary or indirectly through a company in which we have an investment accounted for under the equity method. For additional information regarding our equity method investments, please read Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          The following table shows the approximate capacity (on a net basis in accordance with our ownership interest) of each of our primary onshore natural gas pipeline systems and an estimate of capacity utilization for the periods in which we owned these assets. The utilization rates for the assets we acquired in the GulfTerra Merger are for the three months that we owned them during 2004 (October through December).

          The following table reflects overall throughput rates of our onshore natural gas pipelines (on a net basis in accordance with our ownership interest) for the periods in which we owned them during 2004, 2003 and 2002. The throughput rate for 2004 increased as a result of onshore natural gas pipeline assets acquired in the GulfTerra Merger on September 30, 2004.

14

          The following is a brief description of each of our primary onshore natural gas pipeline assets, all of which we operate:

          Texas Intrastate System. The Texas Intrastate System gathers and transports natural gas from supply basins in Texas and offshore in the Gulf of Mexico to local gas distribution companies and electric generation and industrial customers. This system has over 100 interconnections and serves important natural gas producing and market areas in Texas, including natural gas-fired electric plants and other key markets, such as Corpus Christi, the San Antonio/Austin area, the Beaumont/Orange area, and the large Houston Ship Channel industrial market. The Texas Intrastate System consists of the GulfTerra Texas Intrastate natural gas gathering system, the TPC Offshore natural gas gathering system and the Channel natural gas transmission pipeline.

          The GulfTerra Texas Intrastate natural gas gathering system is one of the largest intrastate pipeline systems in the United States based on miles of pipe. This system consists of 7,292 miles of main lines, laterals and gathering lines and also includes some smaller pipelines in which we own undivided interests. The TPC Offshore natural gas gathering system consists of 197 miles of pipelines located in the coastal waters of south Texas. The TPC Offshore system also includes some smaller pipelines in which we own undivided interests. The Channel pipeline system is a 733-mile intrastate natural gas transmission system located along the Gulf Coast of Texas. We own a 50% undivided interest in the Channel natural gas transmission pipeline.

          San Juan Gathering System. The San Juan Gathering System serves natural gas producers in the San Juan Basin of New Mexico and Colorado, where the system has connections to approximately 9,500 receipt points. This system gathers natural gas from wells in the San Juan Basin and delivers the natural gas to our Chaco natural gas processing facility and to Blanco natural gas processing facility owned by BP and ConocoPhillips. A project is currently underway to increase the capacity on the San Juan gathering system by 130 MMcf/d. The project was started in late 2003 and will be completed in stages through 2006.

          Permian Basin System. The Permian Basin System gathers natural gas from numerous wells in the Permian Basin region of Texas and New Mexico and delivers the natural gas into the El Paso Natural Gas, Transwestern and Oasis pipelines. The Permian Basin System consists of the Waha Natural Gas Gathering System and Carlsbad Natural Gas Gathering System. The Waha system is a 674-mile natural gas gathering system located in the Permian Basin region of Texas. The Carlsbad system is a 803-mile natural gas gathering system located in the Permian Basin region of New Mexico.

          Acadian Gas System. The Acadian Gas System consists of three natural gas pipelines: the 577-mile Cypress pipeline, 438-mile Acadian pipeline, and the 27-mile Evangeline pipeline. The Acadian Gas System is involved in the purchase, sale, transportation and storage of natural gas in Louisiana. We also lease a natural gas storage cavern with approximately 3 Bcf of capacity that is an integral part of this system.

          Alabama Intrastate System. The Alabama Intrastate System is a natural gas pipeline system that serves the coal bed methane-producing regions of Alabama. This system provides transportation and marketing services through the purchase of natural gas from regional producers and others, and sale of natural gas to local distribution companies and others.

          Delmita Gathering System. The Delmita system is a natural gas gathering system located in South Texas that connects approximately 140 producing wells to our Delmita natural gas processing facility. This gathering system is an integral part of the natural gas processing operations of the Delmita facility, the results of operations and assets of which are accounted for under our NGL Pipelines & Services business segment.

          Big Thicket Gathering System. The Big Thicket Gathering System, located in East Texas, gathers natural gas production from area fields and delivers the natural gas to our Indian Springs natural gas processing facility. This gathering system is an integral part of our Indian Springs natural gas processing operations, the results of operations and assets of which are accounted for under our NGL Pipelines & Services business segment.

          Indian Springs Gathering System. In January 2005, we acquired Teco Gas Gathering, LLC from El Paso, which provided us with an indirect 80% interest in the Indian Springs Gathering System. The Indian Springs system consists of three gathering pipelines located in East Texas that gather natural gas production primarily from

15

area fields and deliver the natural gas to our Indian Springs natural gas processing facility.

          Natural Gas Storage Facilities

          We own two underground salt dome natural gas storage facilities located near Hattiesburg, Mississippi that are strategically situated to serve the Northeast, Mid-Atlantic and Southeast natural gas markets. These two facilities have a combined current authorized working storage capacity of 13.5 Bcf, and are capable of delivering in excess of 1.2 Bcf/d of natural gas into five interstate pipeline systems: Transco, Destin Pipeline, Gulf South Pipeline, Southern Natural Gas Pipeline and Tennessee Gas Pipeline. We also lease a natural gas storage facility in Texas having 6.4 Bcf of working capacity and a salt dome natural gas cavern in Louisiana having a working gas storage capacity of 3 Bcf.

          The ability of these facilities to handle high levels of injections and withdrawals of natural gas makes them well-suited for customers who desire the ability to meet load swings and to cover major supply interruption events, such as hurricanes and temporary losses of production. The high injection and withdrawal rates also allow customers to take advantage of favorable natural gas prices and also provide customers the opportunity to quickly respond in situations where they have natural gas imbalance issues on pipelines connected to the storage facility. The characteristics of the salt domes at these facilities permit sustained periods of high delivery, the ability to quickly switch from full injection to full withdrawal and the ability to provide an impermeable storage medium.

          Salt dome storage caverns such as those utilized at our Petal and Hattiesburg storage facilities experience a loss of working capacity of approximately 1% per year due to physical properties of the salt domes. Based on a recent volume verification test at Hattiesburg and recent pressure volume analysis at Petal, we believe the current working gas capacity at Petal and Hattiesburg is 10-15% lower than original capacity. We plan to address this normal loss of working capacity at our Petal and Hattiesburg storage facilities through a flooding program and we do not anticipate that this loss of capacity will affect our ability to provide services to our customers.

          A large portion of the revenue generated by our Petal and Hattiesburg storage facilities is based on fixed monthly demand payments, which are paid regardless of the customer’s usage of the storage facilities. The remaining revenues are primarily generated based on a storage fee per unit of volume stored at these facilities. Seasonality impacts the timing of injections and withdrawals at our natural gas storage facilities. In the winter months, natural gas is needed as fuel for residential and commercial heating, and during the summer months, natural gas is needed by gas-fired electric generation facilities due to the demand for electricity to power air conditioners.

          Competition for natural gas storage is primarily based on location and the ability to deliver natural gas in a timely and reliable manner. Our Hattiesburg and Petal natural gas storage facilities are located in an area in Mississippi that effectively services the Northeastern, Mid-Atlantic and Southeastern natural gas markets, and these facilities have the ability to deliver all of their stored natural gas within a short duration. Our natural gas storage facilities compete with other means of natural gas storage, including other salt dome storage facilities, depleted reservoir facilities, and liquified natural gas and pipelines.

          Most of our Petal storage facility’s working capacity is dedicated under a 20-year, fixed-fee contract. Most of the contracts relating to the Hattiesburg and Wilson natural gas storage facilities expire between 2005 and 2007. We believe that the location of our natural gas storage facilities allow us to compete effectively with other companies who provide natural gas storage services. We believe that many of our natural gas storage contracts will be renewed, although we also expect that once these firm storage contracts have expired, we will experience greater competition for providing storage services. The competition we experience will be dependent upon the nature of the natural gas storage market existing at that time. In addition to long-term contracts, we actively market interruptible storage services at the Petal facility to enhance our revenue generating ability beyond the firm storage contracts.

16

          The following table summarizes the gross working gas authorized capacity of our primary natural gas storage facilities and our ownership interest in each facility as of March 1, 2005.

          The following is a brief description of each of our owned and leased natural gas storage facilities:

          Petal. The Petal storage facility is located near Hattiesburg, Mississippi and consists of two high-deliverability natural gas storage caverns. The Petal facility has a current injection capacity in excess of 430 MMcf/d of natural gas and a withdrawal capacity of 895 MMcf/d of natural gas. The Petal capacity is 94% subscribed, with 7 Bcf dedicated under a 20-year fixed-fee contract to a subsidiary of The Southern Company and 1.65 Bcf subscribed to BP Energy Company. We are in the process of expanding this storage facility. For information regarding this expansion project, please read “Major Construction Projects — Petal Conversion Project” below.

          Hattiesburg. The Hattiesburg storage facility is located less than one mile from the Petal storage facility and consists of three high-deliverability natural gas storage caverns. The facility has an injection capacity in excess of 175 MMcf/d of natural gas and a withdrawal capacity in excess of 400 MMcf/d of natural gas. The Hattiesburg capacity is currently fully subscribed, primarily with eleven contracts expiring between 2005 and 2007.

          Wilson. The Wilson storage facility interconnects with our Texas Intrastate System and consists of four caverns. The facility, located in Wharton County, Texas, has an injection capacity of 150 to 360 MMcf/d of natural gas and a withdrawal capacity of 800 MMcf/d of natural gas. The Wilson capacity is currently 96% subscribed with contracts expiring between 2006 and 2007.

          Acadian. The Acadian natural gas storage cavern is a rapid-cycle salt dome located in Assumption Parish, Louisiana that is an integral part of our Acadian Gas System. This storage facility has an injection capacity of 80 MMcf/d and a withdrawal capacity of 220 MMcf/d and is primarily used in the management of natural gas volumes on the Acadian Gas System; therefore, it is not generally used as a storage cavern for third-party customers.

          Major Construction Projects

          Petal Conversion Project. In the third quarter of 2004, we began to convert an existing brine well at our existing propane storage complex in Hattiesburg, Mississippi to natural gas service. This conversion, which is expected to cost $18 million, will create a new natural gas storage cavern with 1.8 Bcf of working gas capacity that will be integrated with our existing Petal natural gas storage facility. We expect to have the cavern in service during the second quarter of 2005. We have executed long-term storage agreements with BP for the entire capacity of the new natural gas storage cavern.

          San Juan Optimization Project. In May 2003, we commenced a project relating to our San Juan Basin assets. This project, which is estimated to cost approximately $43 million, is expected to be completed in stages through 2006 and will result in increased capacity of up to 130 MMcf/d on our San Juan natural gas gathering system and increased market opportunities through a new interconnect at the tailgate of our Chaco plant.

17

          Intangible Assets

          At December 31, 2004, the Onshore Natural Gas Pipelines & Services segment included $425.8 million of intangible assets primarily related to customer relationships and other contract-based rights that we own. For information regarding our intangible assets, please read Note 8 of the Notes to Consolidated Financial Statements, which is included under Item 8 of this annual report.

NGL PIPELINES & SERVICES

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

          In general, NGL products (ethane, propane, normal butane, isobutane and natural gasoline) are used as raw materials by the petrochemical industry, feedstocks by refiners in the production of motor gasoline and by industrial and residential users as fuel. Ethane is primarily used in the petrochemical industry as feedstock for ethylene production, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating, engine and industrial fuel. Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient of synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization. Isobutane is fractionated from mixed butane (a mixed stream of normal butane and isobutane) or produced from normal butane through the process of isomerization, principally for use in refinery alkylation to enhance the octane content of motor gasoline, in the production of iso-octane and MTBE, and in the production of propylene oxide. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is primarily used as a blendstock for motor gasoline or as a petrochemical feedstock.

          Natural Gas Processing and related NGL marketing activities

          At the core of our natural gas processing business are 24 processing plants located in Texas, Louisiana, Mississippi and New Mexico, 11 of which were acquired in connection with the GulfTerra Merger. In January 2005, we acquired Teco Gas Processing, LLC from El Paso, which provided us with an indirect 75% interest in the Indian Springs natural gas processing facility. The Indian Springs processing facility, which is located in Polk County, Texas, has capacity to process up to 120 MMcf/d of natural gas and there is an idle 20 MMcf/d production train available for restart to support increases in natural gas volumes. The natural gas processed at the Indian Springs processing facility is sourced from our Indian Springs Gathering System, which we also acquired an interest in from El Paso in January 2005, as well as our nearby Big Thicket Gathering System.

          In general, natural gas produced at the wellhead and in association with crude oil contains varying amounts of NGLs. This “rich” natural gas in its raw form is usually not acceptable for transportation in the nation’s major natural gas pipeline systems or for commercial use as a fuel. Natural gas production from the deepwater Gulf of Mexico and the Rocky Mountains, thus far, has generally been rich in NGLs and typically must be processed to meet pipeline quality specifications. Deepwater natural gas production can yield in excess of 4 gallons of NGLs per Mcf of natural gas processed versus an approximate 1 to 1.5 gallons of NGLs per Mcf of production from the continental shelf areas of the Gulf of Mexico.

          Our natural gas processing facilities can be categorized as two distinct types: (1) straddle plants situated on mainline natural gas pipelines owned either by us or by third parties or (2) field plants that process natural gas through associated gas gathering systems. Natural gas processing plants remove the NGLs from the natural gas stream, enabling the natural gas to meet transmission pipeline and commercial quality specifications. In addition, on an energy equivalent basis, NGLs generally have a greater economic value as a raw material for petrochemicals and motor gasoline than their value as components of the natural gas stream. After extraction, we typically transport the mixed NGLs to a centralized facility for fractionation into purity NGL products such as ethane, propane, normal butane, isobutane and natural gasoline. The purity NGL products can then be used in our NGL marketing activities to meet contractual requirements or sold on spot and forward markets.

18

          Our natural gas processing business and NGL marketing activities encounter competition from fully integrated oil companies, intrastate pipeline companies, major interstate pipeline companies and their non-regulated affiliates, and independent processors. Each of our competitors has varying levels of financial and personnel resources, and competition generally revolves around price, service and location. Our integrated midstream energy asset system affords us flexibility in meeting our customers’ needs. While many companies participate in the natural gas processing business, few have a presence in significant downstream activities such as NGL fractionation and transportation, import/export services and NGL marketing as we do. Our competitive position and presence in these downstream businesses allow us to extract incremental value while offering our customers enhanced services, including comprehensive service packages.

          In general, we provide natural gas processing services under five types of arrangements: percent-of-liquids contracts, margin-band contracts, fee-based contracts, hybrid contracts (mixed percent-of-liquids and fee-based) and keepwhole contracts. The key features of each type of contract are described below:

	•	Percent-of-liquids contracts. Under this type of agreement, we receive a percentage of mixed NGLs extracted from a producer’s natural gas stream. The producer either retains title to or receives the value associated with the remaining percentage of mixed NGLs extracted and is responsible for the cost of PTR (see below) with respect to 100% of the mixed NGLs extracted. We derive a profit from percent-of-liquids arrangements to the extent that revenues from our sale and delivery of the mixed NGLs we extracted exceed the sum of our plant operating costs and any other costs such as fractionation and pipeline fees that we might incur. At December 31, 2004, approximately 33% of the natural gas volumes we process were done so under percent-of-liquids contracts.
	•	Margin-band contracts. Under this type of agreement, we take ownership of mixed NGLs extracted from a producer’s natural gas stream. In return, we pay the producer consideration based upon the energy value of the mixed NGLs we extract from the natural gas stream and that of the fuel consumed by our plant in the extraction process. Collectively, these energy values are referred to as plant thermal reduction (“PTR”). The consideration we pay to a producer is generally based on the price of natural gas multiplied by the quantity of PTR extracted or used; however, such consideration is reduced based on the total volume of gas that we process. We derive a profit from these arrangements to the extent that revenues from our sale and delivery of the mixed NGLs we extracted exceed the sum of the consideration (which may be further adjusted , see “CAONO” below) paid to the producer, our plant operating costs and any other costs such as fractionation and pipeline fees that we might incur. At December 31, 2004, approximately 26% of the natural gas volumes we process were done so under margin-band contracts.
		The most significant contract of this type affecting our natural gas processing business is the Shell agreement, which grants us the right to process Shell’s current and future production within state and federal waters of the Gulf of Mexico. The Shell processing agreement includes a life of lease dedication, which may extend the agreement well beyond its initial 20-year term ending in 2019. This contract was amended effective April 1, 2004 to include (1) the reduction in consideration based upon the total volume of gas processed, and (2) a revision to the CAONO mechanism discussed below. In general, the amended contract includes the following rights and obligations:

	•	the exclusive right, but not the obligation in all cases, to process substantially all of Shell’s Gulf of Mexico natural gas production; plus
	•	the exclusive right, but not the obligation in all cases, to process all natural gas production from leases dedicated by Shell for the life of such leases; plus
	•	the right to all title, interest and ownership in the mixed NGLs extracted by our gas processing plants from Shell’s natural gas production from such leases; with
	•	the obligation to re-deliver to Shell the natural gas stream after any mixed NGLs are extracted.

The amended contract contains a revised mechanism (termed “Consideration Adjustment Outside of Normal Operations” or “CAONO”) to adjust the value of the consideration we pay to Shell. The revised

19

CAONO provides for an economic “floor” which, in conjunction with the reduction in consideration that we pay based on the total volume of gas processed, provides us with an acceptable return on the processing of Shell’s gas and provides Shell with relative assurance that its gas will continue to be processed during periods when gas processing economics are negative (times when we would normally choose not to process Shell’s gas). The revised CAONO also provides for an economic “ceiling” whereby Shell receives certain portions of the economic gain we realize when such gains reach certain threshold levels.

	•	Fee-based contracts. Under this type of agreement, we earn a fee based on the volume of natural gas we process. The producer either retains title to or receives the value associated with any mixed NGLs extracted and is responsible for all PTR costs. We derive a profit from fee-based arrangements to the extent that the fees we earn are greater than our plant operating costs. At December 31, 2004, approximately 18% of the natural gas volumes we process were done so under fee-based contracts.
	•	Hybrid contracts. Under this type of agreement, we typically provide processing services to a producer under a percent-of-liquids arrangement with the producer having a processing election on a monthly basis. In general, if a producer elects to not process under a percent-of-liquids arrangement, we process the natural gas under either a fee-based arrangement or in certain cases on a keepwhole basis if we realize greater economic gain. The intent of such arrangements is to give both producers and processors the incentive to process natural gas during periods of natural gas price volatility, especially during those periods when the price of natural gas is high relative to the economic value of NGLs. At December 31, 2004, approximately 14% of the natural gas volumes we process were done so under hybrid contracts.
	•	Keepwhole contracts. Under this type of agreement, we take ownership of mixed NGLs extracted from a producer’s natural gas stream and in return, we either return a quantity of natural gas with equivalent energy value as the PTR or pay the producer for the market value of the PTR. At December 31, 2004, approximately 9% of the natural gas volumes we process were done so under keepwhole contracts.

          In general, our percent-of-liquids and hybrid, and keepwhole contracts give us the right (but not the obligation) to process natural gas for a producer; thus, we are protected from processing at an economic loss during times when the sum of our costs exceeds the value of the mixed NGLs of which we would take ownership. Generally, our natural gas processing agreements have terms ranging from month-to-month to life of the producing lease. Intermediate terms of one to ten years are also common.

          As noted previously, under certain processing arrangements, we take title to a portion of the mixed NGLs that are extracted by our natural gas processing plants. Once this mixed NGL volume is fractionated into purity NGL products (ethane, propane, normal butane, isobutane and natural gasoline), we use them to meet contractual requirements or sell them on spot and forward markets as part of our NGL marketing activities. As part of these marketing activities, we have a number of isobutane sales contracts. To fulfill our obligations under these sales contracts, we can purchase isobutane on the open market for resale, sell isobutane from our inventory or pay our isomerization business (which is part of the Petrochemical Services segment) a toll processing fee to process our inventories of imported or domestically-sourced normal and mixed butanes into isobutane. The intersegment expense and revenue recorded as a result of utilizing the services of our isomerization business is eliminated in consolidation.

          In support of its commercial goals, our NGL marketing activities within this segment rely on inventories of mixed NGLs and purity NGL products. These inventories are the result of accumulated equity NGL production volumes, imports and other spot and contract purchases. Our inventories of ethane, propane and normal butane are typically higher in summer months as each are in higher demand and at higher price levels during winter months. Isobutane and natural gasoline inventories are generally stable throughout the year. Our inventory cycle begins in late-February to mid-March (the seasonal low point); builds through September; remains level until early December; before being drawn down through winter until the seasonal low is reached again.

          To the extent that we are obligated under our margin-band/keepwhole gas processing contracts to pay compensation based upon or replace the PTR extracted from the natural gas stream, we are exposed to various risks, primarily commodity price fluctuations. The prices of natural gas and NGLs are subject to fluctuations in response

20

to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. Periodically, we attempt to mitigate these risks through the use of commodity financial instruments.

          Some of our exposure to commodity price risk is mitigated because natural gas with a high content of NGLs must be processed in order to meet pipeline quality specifications and to be suitable for ultimate consumption. To the extent that natural gas is not processed and does not meet pipeline quality specifications, this unprocessed natural gas and its associated crude oil production may be subject to being shut-in (i.e., not produced). Therefore, producers are motivated to reach contractual arrangements that are acceptable to gas processors in order for gas processing services to be available on a continuous basis (e.g., through contracts that do not expose the processors to natural gas price fluctuations). During periods of extreme commodity price fluctuations, we generally have the right under keepwhole arrangements to withhold processing services from a customer should we and the producer be unsuccessful in reaching acceptable contractual arrangements.

          The following table lists our natural gas processing plants, total and net approximate processing capacities and our ownership interest in each facility at March 1, 2005. We operate the Toca, North Terrebonne, Calumet, Neptune, and Chaco facilities and all of the Texas plants.

21

          The following table shows our natural gas processing volumes and the corresponding overall utilization rates of our natural gas processing capacity for each of the last three years, with both amounts presented on a net basis in accordance with our ownership interests. The table also shows our equity NGL production for each of the last three years. Equity NGL production is defined as the volume of mixed NGLs extracted by the gas plants to which we take title under the terms of processing agreements or as a result of plant ownership interests.

          At December 31, 2004, our NGL marketing activities utilize a fleet of approximately 569 railcars, the majority of which are under short and long-term leases. These railcars are used to deliver feedstocks to our facilities and to transport NGL products throughout the United States. We have rail loading/unloading facilities at Mont Belvieu, Texas; Breaux Bridge, Louisiana; Sorrento, Louisiana and Petal, Mississippi. These facilities service both our rail shipments and those of our customers.

          NGL Pipelines

          Our NGL pipelines transport mixed NGLs and other hydrocarbons to fractionation plants, distribute and collect NGL products to and from petrochemical plants and refineries and deliver propane to customers along the Dixie pipeline and certain sections of the Mid-America Pipeline System. Our pipelines provide transportation services to customers on a fee basis. Therefore, the results of operations for this business are generally dependent upon the volume of product transported and the level of fees charged to customers (including our NGL and petrochemical marketing activities, which are eliminated in consolidation). Typically, our NGL pipelines do not take title to the products they transport; rather, the shipper retains title and the associated commodity price risk.

          In the markets we serve, we compete with a number of intrastate and interstate liquids pipeline companies (including those affiliated with major oil, petrochemical and gas companies) and barge, rail and truck fleet operators. In general, our NGL pipelines compete with these entities in terms of transportation fees and service. We believe that our pipeline systems offer significant flexibility in rendering transportation services for our customers due to the large number of receipt and delivery points that we can offer to them.

          Taken as a whole, this business area has not exhibited a significant degree of seasonality. However, propane transportation volumes are generally higher in the October through March timeframe due to increased use of propane for heating in the upper Midwest and southeastern United States. In addition, our NGL pipeline systems are subject to various types of regulation. For a discussion of the general impact of governmental regulation on our business, please read “The Company’s Operations — Regulation and Environmental Matters” beginning on page 34.

          The following table summarizes our primary NGL pipeline transportation and distribution networks at March 1, 2005. Our ownership interest in each pipeline is held either through a consolidated subsidiary or indirectly through a company in which we have an investment accounted for under the equity method. For additional information regarding our equity method investments, please read Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

22

          NGL pipeline utilization

          The maximum number of barrels that these systems can transport per day depends upon the operating balance achieved at a given time between various segments of the systems. Because the balance is dependent upon the mix of products to be shipped and the demand levels at the various delivery points, the exact capacities of the systems cannot be stated. As shown in the following table, the utilization rates of our primary NGL pipelines are measured in terms of throughput (on a net basis in accordance with our ownership interest).

23

          The following is a brief description of each of our primary NGL pipeline assets, all of which we operate except for Dixie, Tri-States and a small portion of the Louisiana Pipeline System.

          Mid-America Pipeline System. The Mid-America Pipeline System (or “Mid-America”) is a regulated NGL pipeline system consisting of three NGL pipelines: the 2,548-mile Rocky Mountain pipeline, the 2,740-mile Conway North pipeline, and the 1,938-mile Conway South pipeline. The Mid-America system crosses thirteen states: Wyoming, Utah, Colorado, New Mexico, Texas, Oklahoma, Kansas, Missouri, Nebraska, Iowa, Illinois, Minnesota and Wisconsin.

          The Rocky Mountain pipeline transports mixed NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to the Hobbs hub located on the Texas-New Mexico border. The Conway North segment links the large NGL hub at Conway, Kansas to refineries, petrochemical plants and propane markets in the upper Midwest. In addition, the Conway North segment has access to NGL supplies from Canada’s Western Sedimentary basin through third-party pipeline connections. The Conway South pipeline connects the Conway hub with Kansas refineries and transports NGLs from Conway, Kansas to the Hobbs hub (with interconnections to the Seminole Pipeline System at the Hobbs hub). We also own fifteen unregulated propane terminals that are an integral part of the Mid-America system.

          Approximately 60% of the volumes transported on the Mid-America system are mixed NGLs originating from natural gas processing plants located in the Permian Basin in West Texas, the Hugoton Basin of southwestern Kansas, the San Juan Basin of northwest New Mexico, and the Green River Basin of southwestern Wyoming. The remaining volumes are generally purity NGL products originating from NGL fractionators in the mid-continent areas of Kansas, Oklahoma, and Texas, as well as deliveries from Canada.

          Dixie. The Dixie pipeline is a regulated propane pipeline system extending from Mont Belvieu, Texas and Louisiana to markets in the southeastern United States. Propane supplies transported on this system primarily originate from southeast Texas, southern Louisiana and Mississippi. We purchased a 26.1% interest in Dixie from an affiliate of ChevronTexaco in February 2005 for $40 million, and a 20% interest in Dixie from an affiliate of ConocoPhillips in January 2005 for $31 million. As a result of these acquisitions, Dixie will be a consolidated subsidiary of ours beginning with the first quarter of 2005.

          Seminole. Seminole is a regulated pipeline that transports mixed NGLs and NGL products from the Hobbs hub on the Texas-New Mexico border and the Permian Basin area to Mont Belvieu, Texas. The Seminole pipeline is interconnected with the Mid-America system at the Hobbs hub. The primary source of throughput for Seminole is the volume originating from the Mid-America system. In general, volumes transported by Seminole are ultimately used by petrochemical plants that manufacture various products in southeast Texas.

          Texas NGL System. The Texas NGL System is a network of NGL gathering and transportation pipelines located in south Texas. The system includes 379-miles of pipeline used to gather and transport mixed NGLs from our South Texas natural gas processing facilities to our South Texas fractionation facilities. The pipeline system also includes approximately 660-miles of pipelines that deliver NGL products from our South Texas fractionation facilities to refineries and petrochemical plants located from Corpus Christi to Houston and within the Texas City-Houston area, as well as to common carrier NGL pipelines.

          Louisiana Pipeline System. The Louisiana Pipeline System is a network of nine NGL pipelines located in Louisiana. This system transports mixed NGLs and NGL products originating in southern Louisiana and Texas and serves a variety of customers including major refineries and petrochemical companies along the Mississippi River corridor in southern Louisiana. This system also provides transportation services for our natural gas processing plants, NGL fractionators and other facilities located in Louisiana.

          Promix. The Promix pipeline is a NGL pipeline system that gathers mixed NGLs from 12 natural gas processing plants in Louisiana for delivery to the Promix NGL fractionator. This pipeline system is an integral part of the Promix NGL fractionation facility.

          Lou-Tex NGL. The Lou-Tex NGL pipeline system is used to provide transportation services for NGL products and refinery grade propylene between the Louisiana and Texas markets. We also use this pipeline to

24

transport mixed NGLs from certain of our Louisiana gas processing plants to our Mont Belvieu NGL fractionation facility.

          HSC. The HSC pipeline system is a collection of NGL and petrochemical pipelines extending from our Houston Ship Channel import/export terminal facility and Morgan’s Point Facility to Mont Belvieu, Texas. These pipelines are used to deliver NGL products to third-party petrochemical plants and refineries as well as to deliver feedstocks to our Mont Belvieu facilities. Additionally, the HSC pipeline system includes 91 miles of NGL pipeline acquired with our Morgan’s Point facility in December 2004.

          Tri-States, Belle Rose and Wilprise. The Tri-States, Belle Rose and Wilprise NGL pipelines supply mixed NGLs to the BRF, Norco and Promix NGL fractionators located in Louisiana. The mixed NGLs transported on these systems originate from gas processing facilities located along the Mississippi, Alabama and Louisiana Gulf Coast.

          Chunchula. The Chunchula pipeline system is a NGL pipeline system extending from the Alabama-Florida border to our NGL storage facilities at Petal, Mississippi for further distribution.

          NGL and related product storage

          Our NGL and related product storage facilities are integral parts of our operations. In general, our underground storage wells are used to store mixed NGLs, NGL products and petrochemical products for customers and ourselves. The profitability of our storage operations is primarily dependent upon the volume of material stored and the level of fees charged.

          We operate our storage facilities based on the needs and requirements of our customers in the NGL, petrochemical, heating and other related industries. We usually experience an increase in the demand for storage services during the spring and summer months due to increased feedstock storage requirements for motor gasoline production and a decrease during the fall and winter months when propane inventories are being drawn down for heating needs.

          The following table summarizes gross working capacity of our primary storage assets and our ownership of such capacity (on a net basis in accordance with our ownership interest) in each by state as of March 1, 2005. We operate all of our owned or leased storage facilities, with the exception of certain assets operated for us by Shell in Louisiana and Mississippi.

          We store NGL and petrochemical products for customers in our storage facilities for a fee. The amount of storage capacity available for third party customer storage activity varies daily depending on our plant processing storage requirements. At times, we provide some of our processing customers with short-term storage services

25

(typically 30 days or less) at nominal fees when they cannot take immediate delivery of products. Segment revenues include fees charged to our NGL and petrochemical product marketing activities for their use of the storage facilities. These intrasegment revenues and offsetting expenses are eliminated in financial statement consolidation.

          Our competitors in this area are integrated major oil companies, chemical companies and other storage and pipeline companies. Major oil and gas companies occasionally use their proprietary storage assets to store for third party customers, thereby entering into competition with us and other storage capacity providers. We compete with other storage service providers primarily in terms of the fees charged, number of pipeline connections and operational dependability.

          NGL import and export facilities

          We lease and operate NGL import and export facilities and own a barge dock located on the Houston Ship Channel in southeast Texas. Our import facility enables NGL tankers to be offloaded at their maximum unloading rate of 10,000 barrels per hour, thus minimizing the amount of time that a tanker is idle and increasing the number of vessels that can be offloaded. This NGL import facility is primarily used to offload volumes bound for our NGL storage and processing facilities near Mont Belvieu, Texas. In addition, we own an NGL export facility located at the same terminal as our import facility. Our export facility includes an NGL products chiller and related equipment used for loading refrigerated marine tankers for third-party export customers. Our export facility can load vessels with refrigerated propane and butane at rates up to 5,000 barrels per hour. In December 2004, we acquired a barge dock having the capability to load or unload two barges simultaneously, at a maximum load-out rate of approximately 5,000 barrels per hour. Our combined NGL import and export volumes for the years ended December 31, 2004, 2003 and 2002 were 69 MBPD, 79 MBPD and 41 MBPD, respectively.

          Our import and export operations compete with those operated by Dow, Dynegy and ChevronTexaco primarily in terms of loading and offloading volumes per hour. Our competitive position is enhanced because of our related storage and pipeline assets at Mont Belvieu, which allow us to load and offload ships very efficiently. The profitability of import and export activities primarily depends upon the available quantities of NGLs to be loaded and offloaded and the fees we charge associated with each service. In general, our import volumes peak during the spring and summer months and our export volumes are at their highest levels during the winter months.

          NGL Fractionation

          NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane, normal butane and natural gasoline. The three primary sources of mixed NGLs fractionated in the United States are (i) domestic natural gas processing plants, (ii) domestic crude oil refineries and (iii) imports of butane and propane mixtures. The mixed NGLs delivered from domestic natural gas processing plants and crude oil refineries to our NGL fractionation facilities are typically transported by NGL pipelines and, to a lesser extent, by railcar and truck.

          Recoveries of mixed NGLs by gas processing plants represent the largest source of volumes processed by our NGL fractionators. When operating and extraction costs of gas processing plants are higher than the incremental value of the NGL products that would be received by NGL extraction, the recovery levels of certain NGL products such as ethane may be reduced. This leads to a reduction in volumes available for NGL fractionation. The increase or decrease in NGL recovery levels is a primary factor behind changes in gross fractionation volumes.

          Based upon industry data, we believe that sufficient volumes of mixed NGLs, especially those originating from Gulf Coast and Rocky Mountain natural gas processing plants, will be available for fractionation in commercially viable quantities for the foreseeable future. These gas processing plants are expected to benefit from anticipated increases in natural gas production from emerging deepwater developments in the Gulf of Mexico offshore Louisiana and in the Rockies. Deepwater natural gas production has historically had a higher concentration of NGLs than continental shelf or domestic land-based production along the Gulf Coast. In addition, through connections with our Mid-America and Seminole pipeline systems, our Mont Belvieu NGL fractionator has access to NGLs from additional major supply basins in North America, including the San Juan Basin NGL production areas. Lastly, significant volumes of mixed NGLs are contractually committed to our NGL fractionation facilities by joint owners and third-party customers.

26

          The majority of our NGL fractionation facilities process mixed NGL streams for third-party customers and to support our NGL marketing activities under fee-based arrangements. These fees (typically in cents per gallon) are subject to adjustment for changes in certain fractionation expenses, including natural gas fuel costs. At our Norco facility, we perform fractionation services for certain customers under percent-of-liquids contracts whereby we retain a percentage of the NGLs we fractionate for them as our payment. The results of operations of our NGL fractionation business are dependent upon the volume of mixed NGLs fractionated and either the level of fractionation fees charged (under fee-based contracts) or the value of NGLs received (under percent-of-liquids arrangements). We are exposed to fluctuations in NGL prices to the extent we fractionate volumes for customers under percent-of-liquids arrangements. Our tolling (or fee-based) customers generally retain title to the NGLs that we process for them. Overall, the NGL fractionation business exhibits little to no seasonal variation.

          Although competition for NGL fractionation services is primarily based on the fractionation fee, the ability of an NGL fractionator to obtain mixed NGLs and distribute NGL products is also an important competitive factor and is a function of the existence of the necessary pipeline and storage infrastructure. NGL fractionators connected to extensive transportation and distribution systems such as ours have direct access to larger markets than those with less extensive connections.

          The following table summarizes our primary NGL fractionation assets at March 1, 2005. Our ownership interest in each NGL fractionator is held either through a consolidated subsidiary or indirectly through a company in which we have an investment accounted for under the equity method. For additional information regarding our equity method investments, please read Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

27

          NGL fractionator utilization

          The following table shows fractionation volumes and capacity (on a net basis in accordance with our ownership interest) and the corresponding overall utilization rates of our primary NGL fractionation facilities for the last three years. Net capacity amounts have been adjusted for the timing of acquisitions and facility closures.

          The following is a brief description of our primary NGL fractionation assets, all of which we operate except for VESCO.

          Mont Belvieu. The Mont Belvieu NGL fractionator is one of the largest NGL fractionation facilities in the United States with a gross processing capacity of 210 MBPD. Our facility is located at Mont Belvieu, Texas, which is a key hub of the domestic and international NGL industry. Our Mont Belvieu facility fractionates mixed NGLs from several major NGL supply basins in North America including the Mid-Continent, Permian Basin, San Juan Basin, Rocky Mountain Overthrust, East Texas and the U.S. Gulf Coast. Our Mont Belvieu NGL fractionation facility is supported by long-term fractionation agreements, which accounted for 102 MBPD of net volume in 2004.

          South Texas. The South Texas NGL fractionation facilities (Armstrong, Delmita and Shoup) have a combined capacity of 96 MBPD. These facilities physically occupy the same pad sites as certain of our South Texas natural gas processing facilities. Primarily all of the NGLs fractionated at these facilities are supplied directly from the South Texas NGL processing facilities.

          Promix. Promix owns a 145 MBPD NGL fractionation facility located near Napoleonville, Louisiana. We acquired an additional 16.7% interest in Promix in December 2004, resulting in an increase in our ownership interest to 50%. Promix owns a 410-mile mixed NGL gathering system connected to twelve natural gas processing plants, five NGL storage caverns and a barge loading facility. Promix also receives mixed NGLs from natural gas processing plants on the Mississippi and Alabama Gulf Coast through a connection with our Belle Rose and Tri-States pipelines.

          Norco. The Norco NGL fractionation facility, located in Norco, Louisiana, has a gross capacity of 75 MBPD. Our Norco facility receives mixed NGLs via pipeline from refineries and natural gas processing plants, including the Yscloskey and Toca natural gas processing plants in Louisiana. A portion of the mixed NGLs fractionated at our Norco facility are done so under percent-of-liquids contracts with the remainder of volumes fractionated under a fee-based contract. During 2004, long-term percent-of-liquids contracts exclusive to this facility accounted for approximately 51 MBPD of processing volume.

          BRF. The BRF NGL fractionation facility, located near Baton Rouge, Louisiana, has a gross capacity of 60 MBPD. The BRF facility processes mixed NGLs provided by the co-owners of the facility (Williams, BP and ExxonMobil) from production areas in Alabama, Mississippi and southern Louisiana including offshore Gulf of Mexico areas.

          VESCO. As a result of our VESCO investment, we own a 13.1% interest in a 36 MBPD NGL fractionator located in Plaquemines Parish, Louisiana.

28

          Tebone. The Tebone NGL fractionation facility, located in Ascension Parish, Louisiana, has a gross capacity of 30 MBPD. Our Tebone facility receives mixed NGLs from the North Terrebonne gas processing plant.

          Major Construction Projects

          Rocky Mountain NGL pipeline expansion and related NGL fractionation projects

          In January 2005, we started a project to expand our Mont Belvieu NGL fractionator to accommodate an expected increase in NGLs transported to Mont Belvieu from the Rocky Mountains area. Our Mont Belvieu facility’s current fractionation capacity is up to 210 MBPD of mixed NGLs. This project, which is expected to be completed in the first quarter of 2006 at an estimated total cost of $34.2 million, will increase total fractionation capacity at this facility by 15 MBPD and reduce its energy utilization costs. Additionally, we are reviewing a proposal to construct a new NGL fractionator at our Mont Belvieu complex that could add an additional 60 MBPD of fractionation capacity at this industry hub.

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

          Intangible Assets

          At December 31, 2004, the NGL Pipelines & Services segment included $303.5 million of intangible assets primarily related to customer relationships and other contract-based rights that we own. For information regarding our intangible assets, please read Note 8 of the Notes to Consolidated Financial Statements, which is included under Item 8 of this annual report.

PETROCHEMICAL SERVICES

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

          Propylene fractionation

          Our propylene fractionation business consists primarily of four propylene fractionation facilities located in Texas and Louisiana, and approximately 460 miles of various propylene pipeline systems. In general, propylene fractionation plants separate refinery grade propylene (a mixture of propane and propylene) into either polymer grade propylene or chemical grade propylene along with by-products of propane and mixed butane. Polymer grade propylene can also be produced from chemical grade propylene feedstock. Chemical grade propylene is also a by-product of olefin (ethylene) production. The demand for polymer grade propylene is attributable to the manufacture of polypropylene, which has a variety of end uses, including packaging film, fiber for carpets and upholstery and molded plastic parts for appliance, automotive, houseware and medical products. Chemical grade propylene is a basic petrochemical used in plastics, synthetic fibers and foams. Overall, the propylene fractionation business exhibits little seasonality.

          We compete with numerous producers of polymer grade propylene, which include many of the major refiners on the Gulf Coast. Generally, the propylene fractionation business competes in terms of the level of toll processing fees charged and access to pipeline and storage infrastructure. Our petrochemical marketing activities encounter competition from fully integrated oil companies and various petrochemical companies. Each of our petrochemical marketing competitors has varying levels of financial and personnel resources and competition generally revolves around price, service, logistics and location.

29

          The following table summarizes our primary propylene fractionation assets and ownership at March 1, 2005. Our ownership interest in each propylene fractionation facility is held either directly through a consolidated subsidiary or indirectly through a company in which we have an investment accounted for under the equity method. For additional information regarding our equity method investments, please read Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          The following is a brief description of our primary propylene fractionation assets, all of which we operate:

          Mont Belvieu. We operate three polymer grade propylene fractionation facilities (Splitters I, II and III) in Mont Belvieu, Texas having a combined net capacity of 58 MBPD. Results of operations for our polymer grade propylene plants are generally dependent upon toll processing arrangements and petrochemical marketing activities. Under toll processing arrangements, we are paid fees based on the volume of refinery grade propylene used to produce polymer grade propylene.

          As part of the petrochemical marketing activities associated with Splitters I, II, and III, we have several long-term polymer grade propylene sales agreements, the largest of which is with an affiliate of Shell. To meet our petrochemical marketing obligations, we have entered into several agreements to purchase refinery grade propylene. To limit the exposure of our petrochemical marketing activities to price risk, we attempt to match the timing and price of our feedstock purchases with those of the sales of end products. During 2004, 11 MBPD of our net polymer grade propylene production was associated with toll processing operations with the balance attributable to petrochemical marketing activities.

          BRPC. BRPC is a 23 MBPD chemical grade propylene production facility located near Baton Rouge, Louisiana. This unit, located across the Mississippi River from ExxonMobil’s refinery and chemical plant, fractionates refinery grade propylene produced by ExxonMobil into chemical grade propylene for a toll-processing fee.

          The following table shows net fractionation volumes and capacity (in MBPD, on a net basis in accordance with our ownership interest) and the corresponding overall utilization rates of our propylene fractionation facilities for the last three years. Net capacity amounts have been adjusted for the timing of acquisitions.

30

          Petrochemical pipelines and export terminal

          The following table summarizes our primary petrochemical pipeline transportation and distribution networks at March 1, 2005. Our ownership interest in each pipeline is held either directly through a consolidated subsidiary or indirectly through a company in which we have an investment accounted for under the equity method. For additional information regarding our equity method investments, please read Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          The following is a brief description of our primary petrochemical pipeline assets, all of which we operate with the exception of the OTC Propylene Export Facility:

          Lou-Tex Propylene. The Lou-Tex Propylene pipeline consists of a 291-mile pipeline used to transport propylene from Sorrento, Louisiana to Mont Belvieu, Texas. Currently, this pipeline is used to transport chemical grade propylene for third parties from production facilities in Louisiana to customers in Texas. This system also includes storage facilities and a 28-mile NGL pipeline.

          Lake Charles/Bayport. The Lake Charles/Bayport pipeline system is comprised of two pipelines: a 77-mile system used (in combination with a pipeline owned and operated by ExxonMobil) to distribute polymer grade propylene from Mont Belvieu, Texas to polypropylene plants in Lake Charles, Louisiana and Bayport, Texas; and approximately 10 miles of related polymer grade propylene pipelines located in the La Porte, Texas area.

          Texas City. The Texas City pipeline connects our 50% owned La Porte pipeline to various polymer grade propylene customers. This pipeline runs 28 miles south to 9 delivery locations and ends in the Texas, City, Texas area.

          Sabine Propylene. The Sabine Propylene pipeline system is a 21-mile pipeline used to transport polymer grade propylene from third-party plant facilities in Port Arthur, Texas to a connection with our Lake Charles pipeline.

          La Porte. The La Porte pipeline is a 17-mile pipeline used to distribute polymer grade propylene from Mont Belvieu, Texas to La Porte, Texas. This pipeline is an integral part of our Mont Belvieu propylene fractionation activities.

          Morgan’s Point. The Morgan’s Point pipeline is a 13-mile propylene pipeline extending from our facility at Morgan’s Point, Texas to the nearby Ellington Field.

          OTC Propylene Export Facility. The OTC propylene export facility is an above-ground polymer grade propylene storage and export facility located in Seabrook, Texas. This facility can load vessels of polymer grade propylene at rates up to 5,000 barrels per hour. OTC’s primary competitor is an export operation owned by ChevronPhillips located on the Houston Ship Channel. OTC’s operations are an integral part of our Mont Belvieu propylene fractionation business.

31

          Petrochemical pipeline and export terminal utilization

          The maximum number of barrels that our petrochemical pipelines can transport per day depends upon the operating balance achieved at a given time between various segments of the system. Because the balance is dependent upon the mix of products to be shipped and the demand levels at the various delivery points, the exact capacity of the systems cannot be stated. Utilization of our primary petrochemical pipelines is measured in terms of throughput volumes. Utilization for OTC is measured in terms of volumes loaded. The following table shows the throughput volume for each asset over the last three years (in MBPD, on a net basis in accordance with our ownership interest).

          Butane isomerization

          At March 1, 2005, our isomerization business includes three butamer reactor units and eight associated deisobutanizer units located in Mont Belvieu, Texas, which comprise the largest commercial isomerization complex in the United States. In addition, this business includes a 70-mile pipeline system used to transport high-purity isobutane from Mont Belvieu, Texas to Port Neches, Texas. Our isomerization facilities have an average combined production capacity of 116 MBPD of isobutane. We own and operate the isomerization facilities.

          Our commercial isomerization units convert normal butane into mixed butane, which is subsequently fractionated into normal butane, isobutane and high purity isobutane. The demand for commercial isomerization services depends upon the industry’s requirements for high purity isobutane and isobutane in excess of naturally occurring isobutane produced from NGL fractionation and refinery operations. Isobutane demand is marginally higher in the spring and summer months due to the demand for isobutane-based fuel additives in the production of motor gasoline. The results of operation of this business are generally dependent upon the volume of normal and mixed butanes processed and the level of toll processing fees charged to customers. The principal uses of isobutane are for alkylate used in the production of motor gasoline, propylene oxide and in the production of MTBE and iso-octane.

          The Mont Belvieu isomerization facility provides processing services to meet the needs of third-party customers and our other businesses, including our NGL marketing activities and octane additive production facility. In general, our third-party customers pay us a toll processing fee based on the volume of isobutane we produce for them. Our NGL marketing activities utilize these facilities to convert normal and/or mixed butanes into isobutane in order to satisfy isobutane sales contracts. We also use our isomerization facility to meet the feedstock requirements of our octane additive production facility. The revenues and expenses we record for such intercompany transactions are eliminated in consolidation. During 2004, 49 MBPD of our isobutane production was attributable to third party agreements, with the balance of 27 MBPD related to intercompany arrangements.

          In the isomerization market, we compete primarily with facilities located in Kansas, Louisiana and New Mexico. Competitive factors affecting this business include the level of toll processing fees charged, the quality of isobutane that can be produced and access to pipeline and storage infrastructure. We believe that our isomerization facilities benefit from the integrated nature of our Mont Belvieu complex with its extensive connections to pipeline and storage assets.

32

          The following table shows isobutane production and capacity and overall utilization of the Mont Belvieu facility for the last three years:

          Octane enhancement

          We own a 100% interest in Belvieu Environmental Fuels (“BEF”), which owns an octane additive production facility designed to produce both iso-octane and MTBE, which are motor gasoline additives that increase octane and are used in reformulated motor gasoline blends. We operate the facility, which is located within our Mont Belvieu complex. On September 30, 2003, we purchased an additional 33.3% interest in this facility, at which time BEF became a majority-owned consolidated subsidiary of ours. On September 1, 2004, we acquired the remaining 33.3% interest in BEF.

          Prior to 2005, BEF primarily produced MTBE, the production of which was primarily driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990. In recent years, MTBE has been detected in water supplies. The major source of ground water contamination appears to be leaks from underground storage tanks. As a result of environmental concerns, several states have enacted legislation to ban or significantly limit the use of MTBE in motor gasoline within their jurisdictions. In addition, federal legislation has been drafted to ban MTBE and replace the oxygenate with renewable fuels such as ethanol. Although numerous resulting legal actions have been filed against motor gasoline and MTBE producers, BEF has not been named in any MTBE legal action to date.

          As a result of these developments, we are in the process of modifying the facility to also produce iso-octane, a motor gasoline octane enhancement additive derived from isobutane. We expect iso-octane to be in demand by refiners to replace the amount of octane that is lost as a result of MTBE being eliminated as a motor gasoline blendstock. Depending on the outcome of various factors (including pending federal legislation) the facility may be further modified in the future to produce alkylate.

          BEF produces iso-octane using feedstocks of high-purity isobutane and MTBE using both high-purity isobutane and methanol. The high-purity isobutane feedstock requirements are met using production from our Mont Belvieu isomerization units. BEF’s methanol requirements for MTBE production are met through spot market purchases. We compete with other octane additive manufacturing companies primarily on the basis of price. Historically, MTBE prices have been stronger during the April to September period of each year, which corresponds with the summer driving season. We expect to experience the same seasonal demand for iso-octane. BEF’s iso-octane production can be transported using our HSC Pipeline to a location on the Houston Ship Channel for delivery to customers.

          As a result of declining domestic demand and a prolonged period of weak MTBE production economics, several of BEF’s competitors announced their withdrawal from the marketplace during 2003. Due to the deteriorating business environment and outlook and the completion of its preliminary engineering studies regarding conversion alternatives, BEF evaluated the carrying value of its long-lived assets for impairment during the third quarter of 2003. This review indicated that the carrying value of its long-lived assets exceeded their collective fair value, which resulted in a non-cash asset impairment charge of $67.5 million. Our share of this loss was $22.5 million and is recorded as a component of “Equity in income (loss) of unconsolidated affiliates” in our Statements of Consolidated Operations and Comprehensive Income for the year ended December 31, 2003.

          The following table shows BEF’s historical MTBE production volumes and capacity (on a net basis in accordance with our ownership interest) and the corresponding overall utilization rates of the BEF facility for the

33

last three years. Net capacity for 2004 and 2003 has been adjusted for our September 2004 and September 2003 acquisitions of the additional 33.3% interests in the facility.

Intangible Assets

          At December 31, 2004, the Petrochemical Services segment included $51.3 million of intangible assets primarily related to contract-based rights that we own. For information regarding our intangible assets, please read Note 8 of the Notes to Consolidated Financial Statements.

EMPLOYEES

          We do not have any employees. EPCO employs most of the persons necessary for the operation of our business. At December 31, 2004, EPCO had approximately 2,345 employees involved in the management and operations of our business, none of whom were members of a union. We fully reimburse EPCO for the costs of all 2,345 employees. For a detailed discussion of our related party transactions with EPCO, please read Item 13 of this annual report. In addition to EPCO employees, we have engaged approximately 261 contract maintenance and other personnel who support our operations.

MAJOR CUSTOMERS

          Our revenues are derived from a wide customer base. Our largest customer, Shell, accounted for 6.5%, 5.5% and 7.9% of consolidated revenues in 2004, 2003 and 2002, respectively.

REGULATION AND ENVIRONMENTAL MATTERS

          Regulation of our interstate common carrier liquids pipelines

          Our Mid-America, Seminole, Chunchula, Lou-Tex Propylene and Lou-Tex NGL pipelines and certain pipelines in which we own equity interests (Dixie, Tri-States, Wilprise and Belle Rose), along with certain pipelines of the Louisiana Pipeline System, are interstate common carrier liquids pipelines subject to regulation by the FERC under the October 1, 1977 version of the ICA.

          As interstate common carriers, these liquids pipelines provide service to any shipper who requests transportation services, provided that products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. The ICA requires us to maintain tariffs on file with the FERC that set forth the rates we charge for providing transportation services on our interstate common carrier liquids pipelines as well as the rules and regulations governing these services.

          The ICA gives the FERC authority to regulate the rates we charge for service on the interstate common carrier pipelines. The ICA requires, among other things, that such rates be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge proposed new or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff during the term of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to

34

change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of a complaint.

          On October 24, 1992, Congress passed the Energy Policy Act of 1992 (“Energy Policy Act”). The Energy Policy Act deemed liquids pipeline rates that were in effect for the twelve months preceding enactment that had not been subject to complaint, protest or investigation to be just and reasonable under the ICA (i.e., “grandfathered”). The Energy Policy Act also limited the circumstances under which a complaint can be made against such grandfathered rates. In order to challenge grandfathered rates, a party would have to show that it was previously contractually barred from challenging the rates, or that the economic circumstances of the liquids pipeline that were a basis for the rate or the nature of the service underlying the rate had substantially changed or that the rate was unduly discriminatory or preferential.

          The Energy Policy Act required the FERC to issue rules establishing a simplified and generally applicable ratemaking methodology for liquids pipelines, and to streamline procedures in liquids pipeline proceedings. The FERC responded to this mandate by issuing Order No. 561, which, among other things, adopted an indexing rate methodology for liquids pipelines. Under the regulations, which became effective January 1, 1995, liquids pipelines are able to change their rates within prescribed ceiling levels that are tied to an inflation index. Rate increases made within the ceiling levels will be subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. If the indexing methodology results in a reduced ceiling level that is lower than a pipeline’s filed rate, Order No. 561 requires the liquids pipeline to reduce its rate to comply with the lower ceiling. Under Order No. 561, a liquids pipeline may as a general rule utilize the indexing methodology to change its rates. The FERC, however, retained cost-of-service ratemaking, market-based rates, and settlement as alternatives to the indexing approach. While there has been some activity regarding challenge to grandfathered rates in an on-going case against SFPP, L.P. (“SFPP”), an unrelated interstate common carrier for refined products in the western United States, requirements for such a challenge remain uncertain. Portions of Enterprise-owned liquids pipelines have established rates meeting the grandfathering provisions.

          We believe that the rates charged for transportation services on the interstate common carrier liquids pipelines we own or have an interest in are just and reasonable under the ICA. However, we cannot predict what rates we will be allowed to charge in the future for service on our interstate common carrier liquids pipelines. Furthermore, because rates charged for transportation services must be competitive with those charged by other transporters, the rates set forth in our tariffs will be determined based on competitive factors in addition to regulatory considerations.

          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, addressing the rate of SFPP, a publicly traded limited partnership. The Court (i) upheld FERC’s determination that some of SFPP’s rates were grandfathered rates under the Energy Policy Act and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification of those rates; (ii) eliminated the tax allowance in SFPP’s rates because the SFPP limited partnership did not have tax liability; and (iii) remanded the issue of whether SFPP’s revised cost of service without the tax allowance would qualify as a substantially changed circumstance that would justify modification of SFPP’s rates. Because the court remanded the case to the FERC and because the FERC’s ruling on the substantially changed circumstances issue 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. FERC has initiated a public inquiry in Docket No. PL05-5 into the proper treatment of income tax allowances on cost-of-service ratemaking proceeding involving partnerships. Moreover, it is not clear whether FERC’s action taken in response to BP West Coast will be challenged and, if so, whether it will withstand further FERC or judicial review.

          Parties could challenge the rates of our common carrier interstate liquids pipelines and our interstate natural gas pipelines and argue that the rationale in the BP West Coast decision regarding tax allowances should be applied. While it is possible that a party might challenge these rates, it is not possible to predict the likelihood that such a challenge would succeed at the FERC.

35

          Regulation of our interstate and intrastate natural gas pipelines

          The HIOS natural gas pipeline, certain natural gas pipelines in which we own equity interests and the Petal natural gas storage facility, including the 60-mile Petal natural gas pipeline, are regulated by the FERC under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Each system operates under separate FERC-approved tariffs that establish rates, terms and conditions under which each system provides services to its customers. Pursuant to FERC’s jurisdiction over interstate gas pipeline rates, existing pipeline rates may be challenged by customer complaint or by the FERC Staff and proposed rate increases may be challenged by protest.

          In addition, the FERC’s authority over natural gas companies that provide natural gas pipeline transportation or storage services in interstate commerce includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the acquisition, extension, disposition or abandonment of facilities, the maintenance of accounts and records the initiation, extension and discontinuation of services, and various other matters. As noted above, our regulated natural gas pipelines and natural gas storage facility have tariffs established through FERC filings that have a variety of terms and conditions, each of which affect the operations of each system and its ability to recover fees for the services it provides. Generally, changes to these fees or terms can only be implemented upon approval by the FERC. We also own several natural gas intrastate systems that provide transportation and storage pursuant to Section 311 of the NGPA and Section 284 of the Commission’s Regulations. Under Section 311 of the NGPA an intrastate pipeline company may transport gas for an interstate pipeline company or any local distribution company served by an interstate pipeline. The rates for Section 311 service can be established by the FERC or the respective state agency. The associated rates may not exceed a fair and equitable rate. FERC has exempted the construction of facilities used solely for Section 311 transportation from FERC’s certificate requirements.

          In addition to its jurisdiction under the Natural Gas Act and the Natural Gas Policy Act, the FERC also attempted to use the Outer Continental Shelf Lands Act (“OCSLA”) open access provisions to expand its jurisdiction over pipelines on the Outer Continental Shelf . The OCSLA requires that all pipelines operating on or across the outer continental shelf provide open-access, non-discriminatory transportation service on their systems. The U.S. Court of Appeals for the District of Columbia Circuit recently upheld a lower court’s rejection of FERC’s attempt to implement regulations pertaining to “gas service providers” operating on the outer continental shelf. The Minerals Management Service (“MMS”), a bureau in the U.S. Department of the Interior, is the Federal agency that manages the nation’s natural gas, oil and other mineral resources on the outer continental shelf (“OCS”) is also reviewing its jurisdiction with respect to the open-access, non-discriminatory provisions of the OCSLA. We cannot predict what further action FERC or the MMS will take under its OCSLA authority.

          In November 2003, the FERC issued final rules governing the standards of conduct between transmission providers and their energy affiliates that apply to interstate natural gas pipelines and public utilities. The rules became effective on February 9, 2004, and on or before that date, each transmission provider was required to file with the FERC a plan and schedule for implementing the new rules. The rules substantially modify the scope of the FERC’s previous standards of conduct regulations by broadening the definition of “affiliates” covered by the standards of conduct to include “energy affiliates.” The rules make each transmission provider responsible for ensuring complete separation of certain functions between itself and its “energy affiliates” and for compliance with specific information disclosure prohibitions. The rules require that transmission providers conduct training for all employees regarding the scope and content of the rules, and hire or designate a chief compliance officer who is responsible for employee training and answering employee questions regarding the new rules and coordinating audits and investigations with FERC staff, as well as ensuring that the transmission provider complies with the standards of conduct. The rules prohibit employees of a transmission provider from using any third party, affiliate or employee of an affiliate as a conduit for sharing information that is prohibited under the rules from disclosure to energy affiliates.

          On April 16, 2004 and August 2, 2004, the FERC issued Orders on rehearing regarding certain aspects of Order No. 2004. Those rehearing orders were issued as Order No. 2004-A and 2004-B, respectively. Among other things, FERC ruled that the Final Rule was needed and extended the compliance date to September 22, 2004. On July 27, 2004, GulfTerra filed a request for temporary limited waivers of certain requirements of the Standards of Conduct. The requested waivers were necessary because of its merger with Enterprise. GulfTerra requested that the FERC grant limited waivers of compliance for those aspects of the Standards of Conduct that could not be fully

36

addressed until after the merger was consummated. The waiver request was for a period of 45 days after the merger. The FERC granted a 30 day extension after the merger was complete to comply. October 30, 2004 was the date for compliance. On December 21, 2004, the FERC issued Order No. 2004-C which clarified certain aspects of the Order. The Company believes compliance with this Final rule should not be unduly burdensome.

          Regulation of our intrastate common carrier liquids and natural gas pipelines

          Our intrastate NGL and natural gas pipelines are subject to regulation in Alabama, Colorado, Kansas, Illinois, Louisiana, Mississippi, New Mexico and Texas and some of our intrastate natural gas pipelines are subject to regulation by the FERC pursuant to Section 311 of the NGPA. Certain portions of the Louisiana Pipeline System and the majority of the Acadian Gas natural gas pipeline systems are intrastate common carrier pipelines that are subject to various Louisiana state laws and regulations that affect the rates we charge and the terms of service. The Texas Intrastate System and the Alabama Intrastate System are subject to state laws and regulations in Texas and Alabama and to FERC regulation under Section 311 of the NGPA. We also have natural gas underground storage facilities in Louisiana, Mississippi and Texas that are subject to state regulations.

          Intrastate movements of products on the Seminole, Mid-America, Belle Rose and certain pipelines of the Louisiana Pipeline System are provided by them as intrastate common carriers that are subject to various other state laws and regulations that affect the rates we charge and the terms of service. Although state regulation is typically less onerous than at FERC, proposed and existing rates subject to state regulation and the provision of services on a non-discriminatory basis are also subject to challenge by protest and complaint, respectively.

          Other state and local regulation of our operations

          Our business activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies pursuant thereto, governing a wide variety of matters, including marketing, production, pricing, community right-to-know, protection of the environment, safety and other matters.

          For additional information regarding the potential impact of federal, state or local regulatory measures on our business, please read the section titled “Risk Factors - Federal, state or local regulatory measures could materially affect our business,” included under Item 7 of this annual report.

          Environmental Matters

          General Regulations

          We are subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations may, in certain instances, require us to remedy the effects on the environment of the disposal or release of specified substances at current and former operating sites.

          We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as claims for damages to property, employees, other persons and the environment resulting from current or past operations, could result in substantial costs and liabilities in the future. It is possible that new information or future developments, such as increasingly strict environmental laws, could require us to reassess our potential exposure related to environmental matters. As this information becomes available, or other relevant developments occur, we will make accruals accordingly. For a summary of our significant environmental-related accruals, please read Note 1 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          Our offshore pipelines and services are subject to various safety and environmental statutes, including: the OCSLA, the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the Oil Pollution Act of 1990, the Endangered Species Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act and similar state statutes. We have ongoing programs designed to keep our oil and natural gas pipelines and offshore platform operations in compliance

37

with environmental and safety requirements, and we believe that our facilities are in material compliance with the applicable requirements.

          Our onshore natural gas pipelines, gas processing and treating plants and storage facilities are subject to various safety and environmental statutes, including: the Natural Gas Act, the Natural Gas Policy Act, the Hazardous Materials Transportation Act, the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the Oil Pollution Act of 1990, the Endangered Species Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act and similar state statutes. We have ongoing programs designed to keep our natural gas pipelines and gas processing plants in compliance with environmental and safety requirements, and we believe that our facilities are in material compliance with the applicable requirements. As of December 31, 2004, we had a reserve of approximately $21 million, included in other noncurrent liabilities, for environmental remediation costs expected to be incurred over time associated with mercury meters. GulfTerra assumed this liability in connection with its April 2002 acquisition of certain El Paso assets.

          Our NGL pipelines and services are subject to various safety and environmental statutes, including: the Hazardous Materials Transportation Act, the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the Oil Pollution Act of 1990, the Endangered Species Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act and similar state statutes. We have ongoing programs designed to keep our NGL pipelines and NGL fractionation, NGL storage and petrochemical storage operations in compliance with environmental and safety requirements, and we believe that our facilities are in material compliance with the applicable requirements.

          Our petrochemical services operations are subject to various safety and environmental statutes, including: the Hazardous Liquid Pipeline Safety Act, the Resource Conservation and Recovery Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Clean Air Act, the Federal Water Pollution Control Act, the Endangered Species Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act, and similar state statutes. We have ongoing programs designed to keep our storage operations in compliance with environmental and safety regulations, and we believe that our facilities are in material compliance with the applicable requirements.

          Specific Regulations

          Pipelines. Several federal and state environmental statutes and regulations may pertain specifically to the operations of our pipelines. Among these, the Hazardous Materials Transportation Act regulates materials capable of posing an unreasonable risk to health, safety and property when transported in commerce, and the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act authorize the development and enforcement of regulations governing pipeline transportation of natural gas and NGLs. Although federal jurisdiction is exclusive over regulated pipelines, the statutes allow states to impose additional requirements for intrastate lines if compatible with federal programs. New Mexico, Texas and Louisiana have developed regulatory programs that parallel the federal program for the transportation of natural gas and NGLs by pipelines.

          Solid Waste. The operations of our pipelines and plants may generate both hazardous and nonhazardous solid wastes that are subject to the requirements of the Resource Conservation and Recovery Act and its regulations, and other federal and state statutes and regulations. Further, it is possible that some wastes that are currently classified as nonhazardous, via exemption or otherwise, perhaps including wastes currently generated during pipeline operations, may, in the future, be designated as “hazardous wastes,” which would then be subject to more rigorous and costly treatment, storage, transportation, and disposal requirements. Such changes in the regulations may result in additional expenditures or operating expenses for us.

          Hazardous Substances. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and comparable state statutes, also known as “Superfund” laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that cause or contribute to the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a site, the past

38

owner or operator of a site, and companies that transport, dispose of, or arrange for the disposal of the hazardous substances found at the site. CERCLA also authorizes the EPA or state agency, and in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently encompasses natural gas, we may nonetheless handle “hazardous substances,” within the meaning of CERCLA or similar state statutes, in the course of our ordinary operations.

          Air. Our operations may be subject to the Clean Air Act, or CAA, and other federal and state statutes and regulations, that impose certain pollution control requirements with respect to air emissions from operations, particularly in instances where a company constructs a new facility or modifies an existing facility. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. However, we do not believe our operations will be materially adversely affected by and such requirements.

          Water. The Federal Water Pollution Control Act imposes strict controls against the unauthorized discharge of pollutants, including produced waters and other oil and natural gas wastes, into navigable waters. It provides for civil and criminal penalties for any unauthorized discharges of oil and other substances and, along with the Oil Pollution Act of 1990, or OPA, imposes substantial potential liability for the costs of oil or hazardous substance removal, remediation and damages. Similarly, the OPA imposes liability for the discharge of oil into or upon navigable waters or adjoining shorelines. State laws for the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of an unauthorized discharge of pollutants into state waters.

          Communication of Hazards. The Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act and comparable state statutes require those entities that operate facilities for us to organize and disseminate information to employees, state and local organizations, and the public about the hazardous materials used in our operations and our emergency planning.

TITLE TO PROPERTIES

          Our real property holdings fall into two basic categories: (1) parcels that we own in fee, such as the land at the Mont Belvieu complex and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. The fee sites upon which our major facilities are located have been owned by us or our predecessors in title for many years without any material challenge known to us relating to title to the land upon which the assets are located, and we believe that we have satisfactory title to such fee sites. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way or license held by us or to our title to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way and licenses.

          A significant portion of the rights-of-way underlying the San Juan gathering system on Native American lands expire in 2005. We believe we will be able to renew these rights-of-way on terms and conditions that will not be materially adverse to us.

ITEM 3. LEGAL PROCEEDINGS.

          On occasion, we are named as a defendant in litigation relating to our normal business operations, including regulatory and environmental matters. Although we are insured against various business risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activity. We are aware of no significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.

39

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

          There were no matters submitted to a vote of our unitholders during the fourth quarter of 2004.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

          Market Information and Cash Distributions. Our common units are traded on the NYSE under the symbol “EPD.” As of March 1, 2005, there were an estimated 852 unitholders of record of our common units. The following table sets forth, for the periods indicated, the high and low sales price ranges for the common units, as reported on the NYSE Composite Transaction Tape, and the amount, record date and payment date of the quarterly cash distributions paid per common unit.

          The quarterly cash distribution amounts shown in the table above correspond to cash flows for the quarters indicated. The actual cash distributions (i.e., payments to our limited partners) occur within 45 days after the end of such quarter. Although the payment of cash dividends is not guaranteed, we expect to continue to pay comparable cash distributions in the future. 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. On January 19, 2005, we announced that our quarterly cash distribution with respect to the fourth quarter of 2004 was raised to $0.40 per unit, or $1.60 per common unit on an annualized basis.

          We expect to fund our quarterly cash distributions to partners primarily with cash provided by operating activities. For additional information regarding our cash flows from operating activities, please read “Our Liquidity and Capital Resources” included under Item 7 of this annual report.

          Recent sales of unregistered securities. There were no unreported sales of unregistered equity securities during 2004. On December 17, 2003, we sold 4,413,549 Class B special units to an affiliate of EPCO, for $100 million in a private transaction that was exempt from the registration requirements of the Securities Act of 1933, pursuant to Section 4(2) thereof. On July 29, 2004, we requested that our common unitholders approve the conversion of all of the non-voting Class B special units into voting common units on a one-for-one basis at a special meeting that was held on July 29, 2004, to approve our merger with GulfTerra. On this date, our common unitholders approved the conversion and our 4,413,549 Class B special units converted to an equal number of common units.

          Common Units Authorized for Issuance Under Equity Compensation Plan. Please read the information included under Item 12 of this annual report, regarding securities authorized for issuance under equity compensation plans, which information is incorporated by reference into this Item 5.

40

          Repurchases of Common Units. We did not repurchase any of our common units during 2004. Previously, on December 23, 1998, we announced a common units repurchase program whereby we, together with certain affiliates, intended to repurchase up to 2,000,000 of our common units for the purpose of granting options to management and key employees (amount adjusted for the two-for-one unit split in May 2002). As of March 1, 2005, we and our affiliates are authorized to repurchase up to 618,400 additional common units under this repurchase program. Common units repurchased under this program are classified as treasury units.

ITEM 6. SELECTED FINANCIAL DATA.

          The following table sets forth for the periods and at the dates indicated, our selected historical financial data. The selected historical financial data as of and for each of the five years in the period ended December 31, 2004 have been derived from the audited financial statements for the periods indicated. This information should be read in conjunction with our audited financial statements for such periods included under Item 8 of this annual report. In addition, information regarding our results of operations and capital resources and liquidity can be found under Item 7 of this annual report, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” As presented in the table below, dollar amounts (except earnings per unit data) and total units outstanding are in thousands.

          The following information is provided to highlight significant trends and other information regarding our historical operating results, financial position and other financial data. Each section below represents a footnote to the preceding table.

	(1)	In general, our historical operating results and/or financial position have been affected by numerous acquisitions since 2000. Our most significant transaction to date was the GulfTerra Merger, which was completed on September 30, 2004. The aggregate value of the total consideration we paid or issued to complete the GulfTerra Merger was approximately $4 billion. The GulfTerra Merger and our other acquisitions were accounted for using purchase accounting; therefore, the operating results of these acquired entities are included in our financial results prospectively from their respective purchase dates. For additional information regarding such transactions, please read Note 4 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
	(2)	Basic earnings per unit is calculated using the weighted-average number of common, subordinated, restricted and Class B special units that were outstanding during each period. Diluted earnings per unit is

41

		calculated using the weighted-average number of common, subordinated, restricted, performance-based restricted and Class A and B special units outstanding during each period.
	(3)	Earnings per unit and unit count data prior to 2002 have been adjusted to reflect the May 2002 two-for-one split of each class of our partnership units.
	(4)	In general, the balances of our long-term and current maturities of debt have increased over time as a result of financing all or a portion of the acquisitions.
	(5)	We regularly issue common units in public offerings and may also issue other types of limited partner interests in connection with acquisitions or other transactions that increase partners’ equity. The increase in partners’ equity since 2000 has been the result of such transactions, with the issuance of 104.5 million in common units valued at $2.4 billion on September 30, 2004 in connection with the GulfTerra Merger being our largest. For additional information regarding our partners’ equity and unit history, please read Note 10 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
	(6)	Distributions per common unit represents declared cash distributions with respect to the four fiscal quarters of each period presented.
	(7)	Income from continuing operations includes our results from commodity hedging activities. In order to manage the risks associated with our natural gas processing business and related NGL marketing activities, we may enter into various commodity financial instruments. The primary purpose of these risk management activities is to hedge our exposure to price risks associated with natural gas, NGL production and inventories, firm commitments and anticipated transactions. As a matter of policy, we do not use financial instruments for speculative (or trading) purposes. A variety of factors influence whether or not a particular hedging strategy is successful.
		As a result of incurring significant losses from commodity hedging transactions in early 2002 due to a rapid increase in natural gas prices, we exited those commodity hedging strategies that created the loss. Since that time, we have utilized only a limited number of commodity financial instruments. For additional information regarding our use of financial instruments, please read Note 18 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

42

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

          Enterprise Products Partners L.P. is a publicly traded Delaware limited partnership listed on the NYSE symbol “EPD”. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company” or “Enterprise” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. Certain abbreviated names and other capitalized and industry terms are defined within the glossary of this annual report on Form 10-K.

          We were formed in April 1998 to own and operate certain NGL related businesses of EPCO, Inc. (“EPCO,” formerly Enterprise Products Company). We conduct substantially all of our business through our wholly owned subsidiary, Enterprise Products Operating L.P. (our “Operating Partnership”). We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as “Enterprise GP”). We and Enterprise GP are affiliates of EPCO.

          The following discussion and analysis should be read in conjunction with our audited consolidated financial statements and notes included under Item 8 of this annual report. In addition, the reader should review “Cautionary Statement Regarding Forward-Looking Information” under Item 1 of this annual report for information regarding forward-looking statements made in this discussion. The reader should also review the section titled “Risk Factors” included within this Item 7 discussion for information regarding certain risks inherent in our business. Other risks involved in our business are discussed under “Quantitative and Qualitative Disclosures about Market Risk” included under Item 7A of this annual report. Additionally, please see Part III, Item 13 for a discussion of related-party matters.

TABLE OF CONTENTS

43

RECENT DEVELOPMENTS

          GulfTerra Merger. On September 30, 2004, Enterprise and GulfTerra completed the merger of GulfTerra with a wholly owned subsidiary of Enterprise, with GulfTerra being the surviving entity thereof. Additionally, Enterprise completed certain other transactions related to the merger, including receipt of Enterprise GP’s contribution of a 50% membership interest in 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 was approximately $4 billion.

          As a result of the GulfTerra Merger, 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.

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

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

          The GulfTerra Merger transactions

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

•

Step One. On December 15, 2003, Enterprise purchased a 50% membership interest in GulfTerra GP from El Paso for $425 million in cash. GulfTerra GP owns a 1% general partner interest in GulfTerra. Prior to completion of the GulfTerra Merger, 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 amount was fully repaid with the net proceeds from equity offerings completed during 2004. For additional information regarding changes in our debt obligations since December 31, 2003, please see Note 9 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

•

Step Two. On September 30, 2004, the GulfTerra Merger was consummated and GulfTerra and GulfTerra GP became wholly owned subsidiaries of Enterprise. The GulfTerra Merger was accounted for using purchase accounting. Step Two of the GulfTerra Merger included the following transactions:

		•	Immediately prior to closing the GulfTerra Merger, Enterprise 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 membership interest in Enterprise GP), which obtained the funds from a loan from EPCO (which indirectly owns the remaining membership interests 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

44

		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 certain South Texas midstream assets from El Paso for $155.3 million in cash. Pursuant to written agreements, our purchase of the South Texas midstream assets was effective September 1, 2004.

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

          In connection with the GulfTerra Merger, we are required under a consent decree to sell our 50% interest in Starfish, which owns the Stingray natural gas pipeline and related gathering pipelines and dehydration and other facilities located in south Louisiana and the Gulf of Mexico offshore Louisiana by March 31, 2005. In January 2005, we entered into a contract with a third party to sell this investment for approximately $41.2 million. We expect to close this sale during the first quarter of 2005. The sale requires FTC approval under the terms of the consent decree relating to the GulfTerra Merger and is subject to other customary closing conditions. Additionally, under the same consent decree, we were required to sell our undivided 50% interest in a Mississippi propane storage facility by December 31, 2004. We sold our interest in this facility during the fourth quarter of 2004.

          For additional information regarding the GulfTerra Merger and our other business combinations and asset acquisitions completed during 2004 (including selected pro forma financial information), please read Note 4 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          Acquisition of El Paso’s Interests in Enterprise and Enterprise GP by affiliates of EPCO. In January 2005, affiliates of EPCO acquired a 9.9% membership interest in Enterprise GP and 13,454,499 Enterprise common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and its affiliates own 100% of the membership interests of Enterprise GP and approximately 37.4% of our total outstanding common units. El Paso no longer owns any interest in us or Enterprise GP.

          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 (consisting of Anadarko, Dominion, Kerr-McGee, Spinnaker and Devon) for the dedication, processing and gathering of natural gas and condensate production from several natural gas fields in the Atwater Valley, DeSoto Canyon and Lloyd Ridge areas 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/d of natural gas. The platform, which is estimated to cost approximately $385 million, will be operated by Anadarko. Cal Dive is our 20% joint venture partner in the Independence Hub Platform project. Additionally, we will construct, own, and operate the 134-mile Independence Trail natural gas pipeline system, which will have a throughput capacity of approximately 850 MMcf/d of natural gas. The pipeline system, which is estimated to cost $280 million, will transport production from the Independence Hub platform to the Tennessee Gas Pipeline.

          Rocky Mountain NGL pipeline expansion and related NGL fractionation projects. In January 2005, we started a project to expand our Mont Belvieu NGL fractionator to accommodate increased production of NGLs being transported to Mont Belvieu from the Rocky Mountain area. Our Mont Belvieu facility’s current fractionation capacity is up to 210 MBPD of mixed NGLs. This project, which is expected to be completed in the first quarter of 2006 at an estimated total cost of $34.2 million, will increase total fractionation capacity at this facility by 15 MBPD and reduce its energy costs. Additionally, we are reviewing a proposal to construct a new NGL fractionator at our Mont Belvieu complex that could add an additional 60 MBPD of fractionation capacity at this industry hub.

          Currently, the Rocky Mountain segment of our Mid-America pipeline system transports up to 225 MBPD of NGLs from the major producing basins in Wyoming, Utah, Colorado and New Mexico to the Hobbs station on the Texas-New Mexico border. The Western Expansion Project would increase the capacity of this pipeline to 275 MBPD. Permitting, engineering and design work are in progress. We submitted a draft environmental assessment and plan of development to the appropriate regulatory agencies during the first quarter of 2005. Contingent upon

45

receiving all required permits and regulatory approvals, construction could begin as early as the fourth quarter of 2005.

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

          February 2005 equity offering. In February 2005, we sold 17,250,000 common units (including the over-allotment amount of 2,250,000 common units which closed on March 11, 2005) to the public at an offering price of $27.05 per unit. Net proceeds from this offering, including Enterprise GP’s proportionate net capital contribution of $9.1 million, were approximately $456.5 million after deducting applicable underwriting discounts, commissions and estimated offering expenses of $19.7 million. The net proceeds from this offering, including Enterprise GP’s proportionate net capital contribution, were used to repay our 364-Day Acquisition Credit Facility, to temporarily reduce indebtedness outstanding under our Multi-Year Revolving Credit Facility or for general partnership purposes.

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

          March 2005 private senior notes offering. On February 15, 2005, our Operating Partnership sold $500 million in principal amount of senior notes in a private offering, comprised of $250 million in principal amount of 10-year senior unsecured notes and $250 million in principal amount of 30-year senior unsecured notes. The 10-year notes (“Senior Notes I”) were issued at 99.379% of their principal amount and have fixed-rate interest of 5.00% and a maturity date of March 1, 2015. The 30-year notes (“Senior Notes J”) were issued at 98.691% of their principal amount and have fixed-rate interest of 5.75% and a maturity date of March 1, 2035. The Operating Partnership used the net proceeds from the issuance of Senior Notes I and J to repay $350 million of indebtedness outstanding under Senior Notes A which was due on March 15, 2005 and the remaining proceeds for general partnership purposes, including the temporary repayment of indebtedness outstanding under the Multi-Year Revolving Credit Facility. This transaction closed on March 2, 2005. For additional information regarding our debt obligations, please read "Liquidity and Capital Resources — Our Debt Obligations” included within this Item 7 discussion and Note 9 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          March 2005 $4 Billion Universal Shelf Registration Filing. On March 3, 2005, we filed a universal shelf registration statement with the SEC registering the issuance of $4 billion of partnership equity and public debt obligations. In connection with this registration statement, we also registered for resale 36,572,122 common units currently owned by Shell and 4,427,878 common units that had been sold by Shell to Kayne Anderson MLP Investment Company in December 2004. We are obligated to register the resale of these common units under a registration rights agreement we executed with Shell in connection with our acquisition of certain of Shell’s Gulf Coast midstream energy businesses in September 1999. For additional information regarding our equity and debt offerings, please read “Our Liquidity and Capital Resources” included within this Item 7 discussion.

46

OUR RESULTS OF OPERATIONS

          As a result of completing the GulfTerra Merger on September 30, 2004, our Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2004 includes three months of results of operations from the GulfTerra assets. The effective closing date of our purchase of the South Texas midstream assets was September 1, 2004; thus, our Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2004 includes four months of results of operations from the South Texas midstream assets.

          As a result of the GulfTerra Merger, we have reorganized our reportable business segments, as described below. We have also revised our prior segment information in order to conform to the current business segment operations and presentation.

          We have segregated our business activities into four reportable business segments: Offshore Pipelines & Services, Onshore Natural Gas Pipelines & Services, NGL Pipelines & Services, and Petrochemical Services. Our business segments are generally organized and managed according to the type of services rendered and products produced and/or sold. For a listing of the major components of each of our four new business segments, and the principal operating assets included within each of the major components, please read Note 19 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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

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

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

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

          The Other non-segment category is presented for financial reporting purposes only to reflect the historical equity earnings we received from GulfTerra GP and our underlying investment in this entity at December 31, 2003. We acquired a 50% membership interest in GulfTerra GP on December 15, 2003 in connection with Step One of the GulfTerra Merger. Our investment in GulfTerra GP was accounted for using the equity method until the GulfTerra Merger was completed on September 30, 2004. On that date, GulfTerra GP became a wholly owned consolidated subsidiary of ours. Since the historical equity earnings of GulfTerra GP were based on net income amounts allocated to it by GulfTerra, it is impractical for us to allocate the equity income we received during the periods presented to each of our new business segments. Therefore, we have segregated equity earnings from GulfTerra GP from our other segment results to aid in comparability between the periods presented.

          We evaluate segment performance based on the non-GAAP financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results.

47

The GAAP measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

          We define total (or consolidated) segment gross operating margin as operating income before: (1) depreciation, depletion and amortization expense; (2) operating lease expenses for which we do not have the payment obligation; (3) gains and losses on the sale of assets; and (4) selling, general and administrative expenses. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest, extraordinary charges and the cumulative effect of changes in accounting principles. Gross operating margin by segment is calculated by subtracting segment operating costs and expenses (net of the adjustments noted above) from segment revenues, with both segment totals before the elimination of intercompany transactions.

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

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

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

          For additional information regarding our investments in and advances to unconsolidated affiliates, please read Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. For additional information regarding our business segments, please read Note 19 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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