UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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, 2005

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

For the transition period from                      to                     .

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)		76-0568219 (I.R.S. Employer Identification No.)

2727 North Loop West, Houston, Texas (Address of Principal Executive Offices)		77008 (Zip Code)

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

Title of Each Class		Name of Each Exchange On Which Registered
Common Units		New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes þ      No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o      No þ

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 a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ             Accelerated filer o             Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o       No þ

The aggregate market value of the common units of Enterprise Products Partners L.P. (“EPD”) held by non-affiliates at June 30, 2005, 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, 2005, was approximately $6.3 billion. This figure excludes common units beneficially owned by certain affiliates, including (i) Dan L. Duncan, (ii) certain trusts established for the benefit of Mr. Duncan’s family and (iii) directors of Enterprise Products GP, LLC (our general partner). There were 390,303,358 common units of EPD outstanding at February 15, 2006.

 

 

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

		Page
		Number
PART I
Item 1. Business			1
Item 1A. Risk Factors			15
Item 1B. Unresolved Staff Comments			29
Item 2. Properties			29
Item 3. Legal Proceedings			40
Item 4. Submission of Matters to a Vote of Security Holders			40
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities			41
Item 6. Selected Financial Data			42
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			43
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			72
Item 8. Financial Statements and Supplementary Data			75
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			152
Item 9A. Controls and Procedures			152
Item 9B. Other Information			156
PART III
Item 10. Directors and Executive Officers of the Registrant			156
Item 11. Executive Compensation			163
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters			165
Item 13. Certain Relationships and Related Transactions			168
Item 14. Principal Accountant Fees and Services			175
PART IV
Item 15. Exhibits and Financial Statement Schedules			176
Financial Statements			75
Signatures			182
Index to Exhibits			183
Waiver of Provisions of the Conflicts Policies and Procedures of 3rd Amended Administrative Services Agreement
Computation of ratio of earnings to fixed charges
List of subsidiaries
Consent of Deloitte & Touche LLP
Section 302 Certification of Robert G. Phillips
Section 302 Certification of Michael A. Creel
Section 1350 certification of Robert G. Phillips
Section 1350 certification of Michael A. Creel

PART I

Item 1. Business.

GENERAL

          Enterprise Products Partners L.P. is a North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, natural gas liquids (“NGLs”), and crude oil, and is an industry leader in the development of pipeline and other midstream infrastructure in the continental United States and Gulf of Mexico. Unless the context requires otherwise, references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. and its subsidiaries.

          We are a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” We were formed in April 1998 to own and operate certain NGL related businesses of EPCO, Inc. (“EPCO”). Our principal executive offices are located at 2727 North Loop West, Houston, Texas 77008 and our telephone number is (713) 880-6500.

          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 Products GP”). Enterprise Products GP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded affiliate, the common units of which are listed on the NYSE under the ticker symbol “EPE.” The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), a wholly owned subsidiary of EPCO. We, Enterprise Products GP, Enterprise GP Holdings and EPE Holdings are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO.

          In September 2004, we completed the “GulfTerra Merger” transactions, whereby, among other transactions, GulfTerra Energy Partners, L.P. (“GulfTerra”) merged with one of our wholly owned subsidiaries. As a result of the GulfTerra Merger, GulfTerra and its subsidiaries and GulfTerra’s general partner (“GulfTerra GP”) became our wholly owned subsidiaries. The GulfTerra Merger greatly expanded our asset base to include numerous natural gas and crude oil pipelines, offshore platforms and other midstream energy assets. Additionally, the GulfTerra Merger included the purchase of various midstream assets from El Paso Corporation (“El Paso”) that are located in South Texas.

           As a large accelerated filer, we electronically file certain documents with the U.S. Securities and Exchange Commission (“SEC”). We file annual reports on Form 10-K; quarterly reports on Form 10-Q; and 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 statements and related documents in connection with equity or debt offerings. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, 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 and other information regarding registrants 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) 880-6521 for paper copies of these reports free of charge.

          As generally used in the energy industry and in this document, the identified terms have the following meanings:

/d		= per day
BBtus		= billion British Thermal units
Bcf		= billion cubic feet
MBPD		= thousand barrels per day
Mdth		= thousand dekatherms
MMBbls		= million barrels
MMBtus		= million British thermal units
MMcf		= million cubic feet
Mcf		= thousand cubic feet

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

          This annual report contains various forward-looking statements and information that are based on our beliefs and those of Enterprise Products GP, 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 Enterprise Products GP believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor Enterprise Products 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 as described in more detail in Item 1A of this annual report. 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.

BUSINESS STRATEGY

          We operate an integrated midstream asset network within the United States that includes natural gas gathering, processing, transportation and storage; NGL fractionation (or separation), transportation, storage and import and export terminaling; crude oil transportation and offshore production platform services. Our business strategy is to:

	§		capitalize on expected increases in natural gas, NGL and crude oil production resulting from development activities in the Rocky Mountain region and Gulf of Mexico;
	§		maintain a balanced and diversified portfolio of midstream energy assets and expand this asset base through growth capital 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.

          Part of our business strategy involves expansion through growth capital projects. We expect that these projects will enhance our existing asset base and provide us with additional growth opportunities in the future. For information regarding our growth capital projects, please read “Capital Spending” included under Item 7 of this annual report.

RECENT DEVELOPMENTS

          For information regarding significant events affecting us during 2005, please read “Recent Developments” included under Item 7 of this annual report, which is incorporated by reference into this Item 1.

SEGMENT DISCUSSION

          Our midstream asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States, Canada and the Gulf of Mexico with domestic consumers and international markets. We have four reportable business segments: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Offshore Pipelines & Services; and (iv) Petrochemical Services. Our business segments are generally organized and managed along our asset base according to the type of services rendered (or technology employed) and products produced and/or sold.

          The following sections present an overview of our business segments, including information regarding the principal products produced, services rendered, seasonality, competition and regulation. Our results of operations and financial condition are subject to a variety of risks. For information regarding our key risk factors, please read Item 1A of this annual report. For listings and descriptions of our principal plant, pipeline and other properties by segment, please read Item 2 of this annual report.

          For information regarding our general revenue recognition policies and other segment-related matters, please read Notes 4 and 17 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          Our business activities are subject to various federal, state and local laws and regulations governing a wide variety of topics, including commercial, operational, environmental and other matters. For a discussion of the principal effects of regulation on each of our business segments, please read “ – Regulation and Environmental” within each of the following segment disclosures. For a general discussion of environmental matters, please read “– Other Matters – Other Environmental” included within this Item 1.

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 12,810 miles and related storage facilities including our Mid-America Pipeline System, Seminole Pipeline and Dixie Pipeline systems and (iii) NGL fractionation facilities located in Texas and Louisiana. This segment also includes our import and export terminal operations.

          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 a 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 isooctane and other octane additives, 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 twenty-four processing plants located in Texas, Louisiana, Mississippi and New Mexico. 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 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 (or separation) 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.

          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, principally ethane, may be reduced or eliminated. This leads to a reduction in NGL volumes available for transportation and fractionation.

          In our natural gas processing activities, we enter into margin-band contracts, percent-of-liquids contracts, percent-of-proceeds contracts, fee-based contracts, hybrid contracts (mixed percent-of-liquids and fee-based) and keepwhole contracts. Under margin-band and keepwhole contracts, we take ownership of mixed NGLs extracted from the producer’s natural gas stream and recognize revenue when the extracted NGLs are delivered and sold to customers on NGL marketing sales contracts. In the same way, revenue is recognized under our percent-of-liquids contracts except that the volume of NGLs we extract and sell is less than the total amount of NGLs extracted from the producers’ natural gas. Under a percent-of-liquids contract, the producer retains title to the remaining percentage of mixed NGLs we extract. Under a percent-of-proceeds contract, we share in the proceeds generated from the producer’s sale of the mixed NGLs we extract on their behalf. If a cash fee for natural gas processing services is stipulated by the contract, we record revenue when the natural gas has been processed and delivered to the producer. The NGL volumes we extract and retain in connection with our processing activities are referred to as our equity NGL production.

          In general, our percent-of-liquids, 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.

          To the extent that we are obligated under our margin-band and keepwhole gas processing contracts to compensate the producer for the energy value of mixed NGLs we extract from the natural gas stream, we are exposed to various risks, primarily commodity price fluctuations. However, our margin band contracts contain terms which limit our exposure to such risks. The prices of natural gas and NGLs are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. Periodically, we attempt to mitigate these risks through the use of commodity financial instruments.

          Our NGL marketing activities generate revenues from the sale and delivery of NGLs obtained through our processing activities and purchases from third parties on the open market. These sales contracts may also include forward product sales contracts. In general, the sales prices referenced in these contracts are market-related and can include pricing differentials for such factors as delivery location.

          NGL pipelines, storage facilities and import/export terminals. Our NGL pipeline, storage and terminalling operations include approximately 12,810 miles of NGL pipelines, 150 million barrels of underground NGL and related product storage working capacity and two import/export facilities.

          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. Revenue from our NGL pipeline transportation agreements is generally based upon a fixed fee per gallon of liquids transported multiplied by the volume delivered. Accordingly, 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 those charged to our NGL and petrochemical marketing activities, which are eliminated in consolidation). The transportation fees charged under these arrangements are either contractual or regulated by governmental agencies, including the Federal Energy Regulatory Commission (“FERC”). Typically, we do not take title to the products transported in our NGL pipelines; rather, the shipper retains title and the associated commodity price risk.

          Our NGL and related product storage facilities are integral parts of our operations. In general, our underground storage wells are used to store our and our customers’ mixed NGLs, NGL products and petrochemical products. Under our NGL and related product storage agreements, we collect a fee based on the number of days a customer has volumes in storage multiplied by a storage rate for each product. Accordingly, the profitability of our storage operations is primarily dependent upon the volume of material stored and the level of fees charged.

          We operate NGL import and export facilities located on the Houston Ship Channel in southeast Texas. Our import facility is primarily used to offload volumes to be delivered to our NGL storage and processing facilities near Mont Belvieu, Texas. Our export facility includes an NGL products chiller and related equipment used for loading refrigerated marine tankers for third-party export customers. Revenues from our import and export services are primarily based on fees per unit of volume loaded or unloaded and may also include demand charges. Accordingly, the profitability of our import and export activities primarily depends upon the available quantities of NGLs to be loaded and offloaded and the fees we charge for these services.

          NGL fractionation. We own or have interests in nine NGL fractionation facilities located in Texas and Louisiana. NGL fractionation facilities separate mixed NGL streams into purity NGL products. 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. 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. Significant volumes of mixed NGLs are contractually committed to our NGL fractionation facilities by joint owners and third-party customers.

          The majority of our NGL fractionation facilities process mixed NGL streams for third-party customers and 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. 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.

          Regulation and Environmental. Our Mid-America, Seminole, Dixie, Chunchula, Lou-Tex NGL pipelines and certain pipelines in which we own equity interests, along with certain pipelines of the Louisiana Pipeline System, are interstate common carrier liquids pipelines subject to regulation by the FERC under the Interstate Commerce Act (“ICA”). As interstate common carriers, these liquids pipelines must 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. We are required 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.

          We believe that the rates charged for transportation services on our 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.

          Intrastate movements of products on the Seminole, Mid-America, Belle Rose and certain pipelines of the Louisiana Pipeline System 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 the FERC, proposed and existing rates subject to state regulation and the provision of services on a non-discriminatory basis are also subject to challenge by protest and complaint, respectively.

          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, Pipeline Safety Improvement Act of 2002 and Community Right-to-Know Act and similar state statutes. We have ongoing programs designed to keep our gas processing plants, NGL pipelines and NGL fractionation, NGL storage and related product storage operations in compliance with environmental and safety requirements, and we believe that our facilities are in material compliance with the applicable requirements.

          The U.S. Department of Transportation issued final rules (effective March 2001 with respect to hazardous liquids pipelines, which include NGL and petrochemical pipelines, and February 2004 with respect to natural gas pipelines) requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and to take measures (including repairs) to protect pipeline segments located in what the rules refer to as “high consequence areas.” We have ongoing programs designed to keep our pipelines in compliance with environmental and safety requirements, and we believe that our facilities are in material compliance with the applicable requirements. For information regarding the costs of our pipeline integrity management program, please read Item 7 of this annual report.

          Seasonality. Our natural gas processing and NGL fractionation operations exhibit little to no seasonal variation. Likewise, our NGL pipeline operations have not exhibited a significant degree of seasonality overall. However, propane transportation volumes are generally higher in the October through March timeframe in connection with increased use of propane for heating in the upper Midwest and southeastern United States. Our facilities located in the southern United States may be affected by weather events such as hurricanes and tropical storms in the Gulf of Mexico.

          We operate our NGL and related product 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 for heating needs. In general, our import volumes peak during the spring and summer months and our export volumes are at their highest levels during the winter months.

          In support of our commercial goals, our NGL marketing activities 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 normally 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 through winter until the seasonal low is reached again.

          Competition. 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.

          In the markets served by our NGL pipelines, we compete with a number of intrastate and interstate liquids pipelines companies (including those affiliated with major oil, petrochemical and gas companies) and barge, rail and truck fleet operations. In general, our NGL pipelines compete with these entities in terms of transportation fees and service.

          Our competitors in the NGL and related product storage businesses area are integrated major oil companies, chemical companies and other storage and pipeline companies. We compete with other storage service providers primarily in terms of the fees charged, number of pipeline connections and operational dependability. Our import and export operations compete with those operated by major oil and chemical companies primarily in terms of loading and offloading volumes per hour.

          We compete with a number of NGL fractionators in Texas, Louisiana and Kansas. Although competition for NGL fractionation services is primarily based on the fractionation fee charged, the ability of an NGL fractionator to receive mixed NGLs, store and distribute NGL products is also an important competitive factor and is a function of the existence of the necessary pipeline and storage infrastructure.

Onshore Natural Gas Pipelines & Services

          Our Onshore Natural Gas Pipelines & Services business segment includes 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 and lease 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, Barnett Shale and Permian supply basins in the Western U.S., 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.

          Certain of our onshore natural gas pipelines generate revenue revenues from transportation agreements where shippers are billed a fee per unit of volume transported (typically in MMBtus) multiplied by the volume delivered. The transportation fees charged under these arrangements are either contractual or regulated by governmental agencies, including the FERC. Intrastate natural gas pipelines (such as our Acadian Gas and Alabama Intrastate systems) may also 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, approximately 94% of the fee-based gathering arrangements of our San Juan Gathering System are calculated using 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.

          Underground natural gas storage. We own two underground salt dome natural gas storage facilities located near Hattiesburg, Mississippi that are ideally situated to serve the domestic Northeast, Mid-Atlantic and Southeast natural gas markets. These facilities (our Petal Gas Storage (“Petal”) and Hattiesburg locations) are capable of delivering in excess of 1.4 Bcf/d of natural gas into five interstate pipeline systems. We also lease underground salt dome natural gas storage caverns that serve markets in Texas and Louisiana.

          The ability of salt dome storage caverns to handle high levels of injections and withdrawals of natural gas benefits 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 of such facilities also allow customers to take advantage of favorable natural gas prices and to quickly respond in situations where they have natural gas imbalance issues on pipelines connected to the storage facility. Our salt dome storage facilities permit sustained periods of high natural gas deliveries, the ability to quickly switch from full injection to full withdrawal.

          Under our natural gas storage contracts, there are typically two components of revenues: (i) fixed monthly demand payments, which are associated with storage capacity reservation and paid regardless of the customer’s usage of the storage facilities, and (ii) storage fees per unit of volume stored at the facilities.

          Regulation and Environmental. Certain of our interstate natural gas pipelines and the Petal natural gas storage facility are regulated by the FERC, which approves rates, terms and other conditions under which these systems can provide services to customers. Pursuant to the FERC’s jurisdiction over interstate gas pipeline rates, existing pipeline rates may be challenged by customer complaint or by the FERC staff and any proposed rate increase by our offshore natural gas pipelines may be challenged by protest. The FERC’s authority over companies that provide natural gas pipeline transportation or storage services also includes 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 covered services; and various other matters. As noted, our regulated natural gas pipelines have tariffs established through FERC filings that have a variety of terms and conditions, each of which affect the operations and profitability of each system. Generally, changes to these fees or terms are subject to approval by the FERC. In addition, our intrastate natural gas pipelines and natural gas storage facilities are subject to a variety of state and local regulations, including those that affect the rates we charge and terms of service.

          Our onshore natural gas pipelines 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, Pipeline Safety Improvement Act of 2002 and Community Right-to-Know Act and similar state statutes. Our onshore natural gas pipelines and storage facilities are also subject to pipeline integrity programs as described under “ – NGL Pipelines & Services – Regulation and Environmental.”

          At December 31, 2005 and 2004, we had a reserve of approximately $21 million for environmental remediation costs expected to be incurred by GulfTerra over time associated with mercury meters. Remediation activities were started during 2005 and are expected to take four years to complete.

          Seasonality. Typically, our onshore natural gas pipelines experience higher throughput rates during the summer months as gas-fired power generation facilities increase output for residential and commercial demand for electricity for air conditioning. Likewise, 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 power generation facilities due to the demand for electricity for air conditioning.

          Competition. 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 economically connected) to the customers we serve.

          Competition for natural gas storage is primarily based on location and the ability to deliver natural gas in a timely and reliable manner. Our natural gas storage facilities compete with other providers of natural gas storage, including other salt dome storage facilities and depleted reservoir facilities. We believe that the locations of our natural gas storage facilities allow us to compete effectively with other companies who provide natural gas storage services.

Offshore Pipelines & Services

          Our Offshore Pipelines & Services business segment includes (i) approximately 1,190 miles of offshore natural gas pipelines strategically located to serve production areas including some of the most active drilling and development regions in the Gulf of Mexico, (ii) approximately 870 miles of offshore Gulf of Mexico crude oil pipeline systems and (iii) seven multi-purpose offshore hub platforms located in the Gulf of Mexico.

          Offshore natural gas pipelines. Our offshore natural gas pipeline systems provide for the gathering and transmission of natural gas from 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.

          Our revenues from offshore natural gas pipelines are derived from fee-based agreements and are typically based on transportation fees per unit of volume transported (typically in MMBtus) multiplied by the volume delivered. These transportation agreements tend to be long-term in nature, often involving life-of-reserve commitments with firm and interruptible components. We do not take title to the natural gas volumes they transported on our natural gas pipeline systems; rather, the shipper retains title and the associated commodity price risk.

          Offshore oil pipelines. We own interests in several offshore oil pipeline systems, which are located in the vicinity of oil-producing areas in the Gulf of Mexico. Typically, these systems receive crude 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.

          The majority of revenues from our offshore crude oil pipelines are derived from purchase and sale arrangements whereby we purchase oil from shippers at various receipt points along our crude oil pipelines for an index-based price (less a price differential) and sell the oil back to the shippers at various redelivery points at the same index-based price. Net revenue recognized from such arrangements is based on a price differential per unit of volume (typically in barrels) multiplied by the volume delivered. In addition, certain of our offshore crude oil pipelines generate revenues based upon a gathering fee per unit of volume

(typically in barrels) multiplied by the volume delivered to the customer. A substantial portion of the revenues generated by our offshore crude oil pipeline systems are attributable to production from reserves committed under long-term contracts for the productive life of the relevant field or contracts for the purchase and sale of crude oil with terms from two to twelve months. The revenues we earn 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.

          Offshore platforms. We have 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 producing 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.

          Revenues from offshore platform services generally consist of demand fees and commodity charges. Demand fees represent fixed-fees charged to customers who use our offshore platforms regardless of the volume the customer delivers to the platform. Revenues from commodity charges are based on a fixed-fee per unit of volume delivered to the platform (typically per MMcf of natural gas or per barrel of crude oil) multiplied by the total volume of each product delivered. Contracts for platform services often include both demand fees and commodity charges, but demand fees generally expire after a contractually fixed period of time.

          Regulation and Environmental. Certain of our offshore natural gas pipelines (primarily our High Island Offshore System) are regulated by the FERC. The jurisdiction of the FERC over these operations is similar to the FERC’s jurisdiction over our interstate natural gas pipelines and the Petal natural gas storage facility as described under “– Onshore Natural Gas Pipelines & Services – Regulation and Environmental.”

          Our offshore pipeline systems are also subject to federal regulation under the Outer Continental Shelf Lands Act (“OCSLA”), which calls for nondiscriminatory transportation on pipelines operating in the outer continental shelf region of the Gulf of Mexico. Each of our oil pipeline systems has continuing programs of inspection and compliance designed to keep all of our facilities in compliance with pipeline safety and pollution control requirements. We believe that our oil pipeline systems are in material compliance with the applicable requirements of these regulations.

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

          Seasonality. Our offshore operations 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.

          Competition. Within their market area, our offshore natural gas and oil pipelines compete with other pipelines (both regulated and unregulated systems) primarily on the basis of price (in terms of transportation fees), available capacity and connections to downstream markets. To a limited extent, our competition includes other offshore pipeline systems, built, owned and operated by producers to handle their own production and, as capacity is available, production for others. We 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 may possess greater capital resources than we have available, which could enable them to address business opportunities more quickly than us.

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 approximately 690 miles of petrochemical pipeline systems.

          Propylene fractionation. Our propylene fractionation business consists primarily of four propylene fractionation facilities located in Texas and Louisiana, and approximately 620 miles of various propylene pipeline systems. These operations also include an export facility located on the Houston Ship Channel and our petrochemical marketing activities.

          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.

          Results of operations for our polymer grade propylene plants are generally dependent upon toll processing arrangements and petrochemical marketing activities. These processing arrangements typically include a base-processing fee per gallon (or other unit of measurement) subject to adjustment for changes in natural gas, electricity and labor costs, which are the primary costs of propylene fractionation and isomerization operations. Our petrochemical marketing activities generate revenues from the sale and delivery of products obtained through our processing activities and purchases from third parties on the open market. In general, the sales prices referenced in these contracts are market-related and can include pricing differentials for such factors as delivery location.

          As part of our petrochemical marketing activities, we have several long-term polymer grade propylene sales agreements. 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.

          Isomerization. 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 commercial isomerization units convert normal butane into mixed butane, which is subsequently fractionated into normal butane, isobutane and high purity isobutane. The principal uses of isobutane are for alkylate used in the production of motor gasoline, propylene oxide and in the production of methyl tertiary butyl ether (“MTBE”) and isooctane. 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.

          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. Our 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.

          Octane enhancement. We own and operate an octane additive production facility located in Mont Belvieu, Texas designed to produce both isooctane and MTBE, which are motor gasoline additives that increase octane and are used in reformulated motor gasoline blends. This facility produces isooctane using feedstocks of high-purity isobutane and MTBE using feedstocks of high-purity isobutane and methanol.

The facility’s high-purity isobutane feedstock requirements are met using production from our isomerization units.

          The production of MTBE was primarily driven by oxygenated fuel programs enacted under the federal Clean Air Act Amendments of 1990, which mandated the use of reformulated gasoline in certain areas of the United States. In recent years, MTBE has been detected in water supplies. The major source of ground water contamination appears to be leaks from underground storage tanks. As a result of environmental concerns, several states enacted legislation to ban or significantly limit the use of MTBE in motor gasoline within their jurisdictions. In addition, the Energy Policy Act of 2005 eliminates the requirement of oxygenates in reformulated motor gasoline.

          As a result of such developments, we modified the facility to produce isooctane in addition to MTBE. These modifications were completed in mid-2005. We expect isooctane 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, the facility may be further modified in the future to produce alkylate, another motor gasoline additive.

          Regulation and Environmental. Our interstate Lou-Tex Propylene pipeline is a common carrier pipeline regulated by the Surface Transportation Board (“STB”). In general, 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. Our petrochemical pipelines are also subject to pipeline integrity programs as described under “ – NGL Pipelines & Services – Regulation and Environmental.” 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.

          Seasonality. Overall, the propylene fractionation business exhibits little seasonality. Our isomerization operations experience slightly higher demand in the spring and summer months due to the demand for isobutane-based fuel additives used in the production of motor gasoline. Likewise, isooctane and MTBE prices have been stronger during the April to September period of each year, which corresponds with the summer driving season.

          Competition. 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. Our petrochemical marketing competitors have varying levels of financial and personnel resources and competition generally revolves around price, service, logistics and location.

          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 also compete with other octane additive manufacturing companies primarily on the basis of price.

OTHER MATTERS

Other Environmental

          We are subject to extensive federal, state and local laws and regulations governing environmental quality and pollution control. These environmental 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 expense accruals accordingly. For a summary of our significant environmental-related costs, please read Note 2 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          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 (“CERCLA”), and comparable state statutes, also known as “Superfund” laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that cause or contribute to the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a site, the past owner or operator of a site, and companies that transport, dispose of, or arrange for the disposal of the hazardous substances found at the site. CERCLA also authorizes the Environmental Protection Agency or state agency, and in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently encompasses crude oil, refined petroleum products, natural gas and NGLs, we may nonetheless handle “hazardous substances,” within the meaning of CERCLA or similar state statutes, in the course of our ordinary operations.

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

          Water. The Federal Water Pollution Control Act imposes strict controls against the unauthorized discharge of pollutants, including produced waters and other oil and natural gas wastes, into navigable waters. It provides for civil and criminal penalties for any unauthorized discharges of oil and other substances and, along with the Oil Pollution Act of 1990 (“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.

Employees

          At December 31, 2005, there were approximately 2,600 persons directly involved in the management, administration and operations of Enterprise Products Partners, approximately 2,365 of which are employees of EPCO that provide services to us under an administrative services agreement. The remaining 235 individuals primarily represent third-party contract personnel. For additional information regarding our relationship with EPCO, please read Item 13 of this annual report.

Significant Customers

          Our revenues are derived from a wide customer base. During 2005, our largest customer, The Dow Chemical Company, accounted for 6.8% of our consolidated revenues. During 2004 and 2003, our largest customer, Shell Oil Company and affiliates (“Shell”), accounted for 6.5% and 5.5% of our consolidated revenues, respectively.

Item 1A. Risk Factors.

          An investment in our common units involves certain risks. If any of these risks were to occur, our business, results of operations, cash flows and financial condition could be materially adversely affected. In that case, the trading price of our common units could decline, and you could lose part or all of your investment.

          Among the key risk factors that may have a direct impact on our business, results of operations, cash flows and financial condition are:

Risks Related to Our Business

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

          We operate predominantly in the midstream energy sector which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs and crude oil. As such, our results of operations, cash flows and financial condition may be materially adversely affected by changes in the prices of these hydrocarbon products and by changes in the relative price levels among these hydrocarbon products. Generally, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors that are impossible to control. These factors include:

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

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

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

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

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

on reserves that are expected to be produced from newly discovered properties that are currently being developed.

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

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

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

          Ethane. If natural gas prices increase significantly in relation to ethane prices, it may be more profitable for natural gas producers to leave the ethane in the natural gas stream to be burned as fuel than to extract the ethane from the mixed NGL stream for sale.

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

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

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

We face competition from third parties in our midstream businesses.

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

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

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

          As of December 31, 2005, we had approximately $4.8 billion of consolidated debt outstanding. The amount of our future debt could have significant effects on our operations, including, among other things:

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

          Our public debt indentures currently do not limit the amount of future indebtedness that we can create, incur, assume or guarantee. Although our Multi-Year Revolving Credit Facility restricts our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial. For information regarding our Multi-Year Revolving Credit Facility, please read Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          Our Multi-Year Revolving Credit Facility and each of our indentures for our public debt contain conventional financial covenants and other restrictions. For example, we are prohibited from making distributions to our partners if such distributions would cause an event of default or otherwise violate a covenant under our Multi-Year Revolving Credit Facility. A breach of any of these restrictions by us could permit our lenders or noteholders, as applicable, to declare all amounts outstanding under these debt agreements to be immediately due and payable and, in the case of our Multi-Year Revolving Credit Facility, to terminate all commitments to extend further credit. For additional information regarding our Multi-Year Revolving Credit Facility, please read Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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

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

          Our strategy contemplates growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversifying our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating and/or pursuing, potential joint ventures, stand alone projects or other transactions that we believe will present opportunities to realize synergies, expand our role in the energy infrastructure business and increase our market position.

          We will require substantial new capital to finance the future development and acquisition of assets and businesses. Any limitations on our access to capital will impair our ability to execute this strategy. If the cost of such capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our initial cost of equity include market conditions, fees we pay to underwriters and other offering costs, which include amounts we pay for legal and accounting services. The primary factors influencing our cost of borrowing include interest rates, credit spreads, covenants, underwriting or loan origination fees and similar charges we pay to lenders.

          In addition, we are experiencing increased competition for the types of assets and businesses we have historically purchased or acquired. Increased competition for a limited pool of assets could result in our losing to other bidders more often or acquiring assets at less attractive prices. Either occurrence would limit our ability to fully execute our growth strategy. Our inability to execute our growth strategy may materially adversely affect our ability to maintain or pay higher distributions in the future.

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

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

	§		difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or business segments;
	§		establishing the internal controls and procedures that we are required to maintain under the Sarbanes-Oxley Act of 2002;

	§		managing relationships with new joint venture partners with whom we have not previously partnered;
	§		inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including with their markets; and
	§		diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.

          If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation, depletion and amortization expenses. As a result, our capitalization and results of operations may change significantly following an acquisition. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our results of operations, cash flows and financial condition. In addition, any anticipated benefits of a material acquisition, such as expected cost savings, may not be fully realized, if at all.

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

          Our growth strategy includes making accretive acquisitions. As a result, from time to time, we will evaluate and acquire assets and businesses that we believe complement our existing operations. We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could negatively impact our results of operations, cash flows and financial condition.

          If consummated, any acquisition or investment would also likely result in the incurrence of indebtedness and contingent liabilities and an increase in interest expense and depreciation and amortization expenses. As a result, our capitalization and results of operations may change significantly following an acquisition. A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our results of operations, cash flows and financial condition.

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

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

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

          We will have significant expenditures for the development and construction of energy infrastructure assets, including some construction and development projects with significant technological challenges. We may not be able to complete our projects at the costs estimated at the time of each project’s initiation.

Substantially all of the common units in us that are owned by EPCO and its affiliates are pledged as security under EPCO’s credit facility. Additionally, all of the member interests in our general partner and all of the common units in us that are owned by Enterprise GP Holdings are pledged under its credit facility. Upon an event of default under either of these credit facilities, a change in ownership or control of us could ultimately result.

           An affiliate of EPCO has pledged substantially all of its common units in us as security under its credit facility. EPCO’s credit facility contains customary and other events of default relating to defaults of EPCO and certain of its subsidiaries, including certain defaults by us and other affiliates of EPCO. An event of default, followed by a foreclosure on EPCO’s pledged collateral, could ultimately result in a change in ownership of us. In addition, the 100% membership interest in our general partner and the 13,454,498 of our common units that are owned by Enterprise GP Holdings are pledged under Enterprise GP Holdings’ credit facility. Enterprise GP Holdings’ credit facility contains customary and other events of default. Upon an event of default, the lenders under Enterprise GP Holdings’ credit facility could foreclose on Enterprise GP Holdings’ assets, which could ultimately result in a change in control of our general partner and a change in the ownership of our units held by Enterprise GP Holdings.

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

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

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

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

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

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

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

          We participate in several joint ventures. Due to the nature of some of these arrangements, each participant in these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features customarily include a corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100%) to authorize more significant

activities. Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business, among others. Thus, without the concurrence of joint venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of us or the particular joint venture.

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

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

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

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

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

An impairment of goodwill and intangible assets could reduce our earnings.

          At December 31, 2005, our balance sheet reflected $494 million of goodwill and $913.6 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Generally accepted accounting principles in the United States (otherwise known as “GAAP”) require us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings

with a correlative effect on partners’ equity and balance sheet leverage as measured by debt to total capitalization.

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

         In addition to our exposure to commodity prices, we have significant exposure to increases in interest rates. As of December 31, 2005, we had approximately $4.8 billion of consolidated debt, of which approximately $3.3 billion was at fixed interest rates and approximately $1.5 billion was at variable interest rates, after giving effect to existing interest swap arrangements. From time to time, we may enter into additional interest rate swap arrangements, which could increase our exposure to variable interest rates. As a result, our results of operations, cash flows and financial condition, could be materially adversely affected by significant increases in interest rates.

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

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

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

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

         The U.S. Department of Transportation issued final rules (effective March 2001 with respect to hazardous liquid pipelines and February 2004 with respect to natural gas pipelines) requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rules refer to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. At this time, we cannot predict the ultimate costs of compliance with this rule because those costs will depend on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing that is required by the rule. We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

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

         Our operations are subject to extensive federal, state and local regulatory requirements relating to environmental affairs, health and safety, waste management and chemical and petroleum products. Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both. Third parties may also have the right to pursue legal actions to enforce compliance.

         We will make expenditures in connection with environmental matters as part of normal capital expenditure programs. However, future environmental law developments, such as stricter laws,

regulations, permits or enforcement policies, could significantly increase some costs of our operations, including the handling, manufacture, use, emission or disposal of substances and wastes.

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

          The FERC regulates our interstate natural gas pipelines and interstate natural gas storage facilities under the Natural Gas Act, and interstate NGL and petrochemical pipelines under the ICA. The STB regulates our interstate propylene pipelines. State regulatory agencies regulate our intrastate natural gas and NGL pipelines, intrastate storage facilities and gathering lines.

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

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

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

          For a general overview of federal, state and local regulation applicable to our assets, please read the regulation and environmental information included under Item 1 of this annual report. This regulatory oversight can affect certain aspects of our business and the market for our products and could materially adversely affect our cash flows.

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

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

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

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

Some of our executive officers and directors face potential conflicts of interest in managing our business.

          Certain of our executive officers and directors are also officers and/or directors of EPCO, the general partner of Enterprise GP Holdings, the general partner of TEPPCO and other affiliates of EPCO. These relationships may create conflicts of interest regarding corporate opportunities and other matters. The resolution of any such conflicts may not always be in our or our unitholders’ best interests. In addition, these overlapping executive officers and directors allocate their time among EPCO, Enterprise GP Holdings, TEPPCO and other affiliates of EPCO. These officers and directors face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition. Please read Item 10 of this annual report for more detailed information on which of our officers and directors serve as officers and/or directors of EPCO, the general partner of Enterprise GP Holdings, the general partner of TEPPCO and other affiliates of EPCO.

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

We may issue additional securities without the approval of our common unitholders.

          Subject to NYSE rules, we may issue an unlimited number of limited partner interests of any type (to parties other than our affiliates) without the approval of our unitholders. Our partnership agreement does not give our common unitholders the right to approve the issuance of equity securities including equity securities ranking senior to our common units. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

	§		the proportionate ownership interest of a common unit will decrease;
	§		the amount of cash available for distributions on each unit may decrease;
	§		the ratio of taxable income to distributions may increase;
	§		the relative voting strength of each previously outstanding unit may be diminished; and
	§		the market price of our common units may decline.

We may not have sufficient cash from operations to pay distributions at the current level following establishment of cash reserves and payments of fees and expenses, including payments to Enterprise Products GP.

           Because distributions on our common units are dependent on the amount of cash we generate, distributions may fluctuate based on our performance. We cannot guarantee that we will continue to pay distributions at the current level each quarter. The actual amount of cash that is available to be distributed each quarter will depend upon numerous factors, some of which are beyond our control and the control of Enterprise Products GP. These factors include but are not limited to the following:

	§		the level of our operating costs;
	§		the level of competition in our business segments;
	§		prevailing economic conditions;
	§		the level of capital expenditures we make;
	§		the restrictions contained in our debt agreements and our debt service requirements;
	§		fluctuations in our working capital needs;

	§		the cost of acquisitions, if any; and
	§		the amount, if any, of cash reserves established by Enterprise Products GP in its sole discretion.

          In addition, you should be aware that our ability to pay the minimum quarterly distribution each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income.

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

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

Cost reimbursements and fees due to Enterprise Products GP may be substantial and will reduce our cash available for distribution to holders of our units.

         Prior to making any distribution on our units, we will reimburse Enterprise Products GP and its affiliates, including officers and directors of Enterprise Products GP, for expenses they incur on our behalf. The reimbursement of expenses could adversely affect our ability to pay cash distributions to holders of our units. Enterprise Products GP has sole discretion to determine the amount of these expenses. In addition, Enterprise Products GP and its affiliates may provide other services to us for which we will be charged fees as determined by Enterprise Products GP.

Enterprise Products GP and its affiliates have limited fiduciary responsibilities to, and conflicts of interest with respect to, our partnership, which may permit it to favor its own interests to your detriment.

         The directors and officers of Enterprise Products GP and its affiliates have duties to manage Enterprise Products GP in a manner that is beneficial to its members. At the same time, Enterprise Products GP has duties to manage our partnership in a manner that is beneficial to us. Therefore, Enterprise Products GP’s duties to us may conflict with the duties of its officers and directors to its members. Such conflicts may include, among others, the following:

	§		neither our partnership agreement nor any other agreement requires Enterprise Products GP or EPCO to pursue a business strategy that favors us;
	§		decisions of Enterprise Products GP regarding the amount and timing of asset purchases and sales, cash expenditures, borrowings, issuances of additional units and reserves in any quarter may affect the level of cash available to pay quarterly distributions to unitholders and Enterprise Products GP;
	§		under our partnership agreement, Enterprise Products GP determines which costs incurred by it and its affiliates are reimbursable by us;
	§		Enterprise Products GP is allowed to resolve any conflicts of interest involving us and Enterprise Products GP and its affiliates;

	§		Enterprise Products GP is allowed to resolve any conflicts of interest involving us and Enterprise Products GP and its affiliates;
	§		Enterprise Products GP is allowed to take into account the interests of parties other than us, such as EPCO, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to unitholders;
	§		any resolution of a conflict of interest by Enterprise Products GP not made in bad faith and that is fair and reasonable to us shall be binding on the partners and shall not be a breach of our partnership agreement;
	§		affiliates of Enterprise Products GP, including TEPPCO, may compete with us in certain circumstances;
	§		Enterprise Products GP has limited its liability and reduced its fiduciary duties and has also restricted the remedies available to our unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. As a result of purchasing our units, you are deemed to consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
	§		we do not have any employees and we rely solely on employees of EPCO and its affiliates;
	§		in some instances, Enterprise Products GP may cause us to borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
	§		our partnership agreement does not restrict Enterprise Products GP from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
	§		Enterprise Products GP intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us;
	§		Enterprise Products GP controls the enforcement of obligations owed to us by our general partner and its affiliates; and
	§		Enterprise Products GP decides whether to retain separate counsel, accountants or others to perform services for us.

           We have significant business relationships with entities controlled by Dan L. Duncan, including EPCO and TEPPCO. For detailed information on these relationships and related transactions with these entities, please read Item 13 included within this annual report.

           Even if unitholders are dissatisfied, they cannot easily remove Enterprise Products GP.

           Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect Enterprise Products GP or its directors and will have no right to elect our general partner or its directors on an annual or other continuing basis.

           Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have no practical ability to remove Enterprise Products GP or the officers or directors of Enterprise Products GP. Enterprise Products GP may not be removed except upon the vote of the holders of at least 60% of our outstanding units voting together as a single class. Because affiliates of Enterprise Products GP currently own approximately 35.6% of our outstanding common units, the removal of Enterprise Products GP as our general partner is not practicable without the consent of both Enterprise Products GP and its affiliates.

          Unitholders’ voting rights are further restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management.

          As a result of these provisions, the trading price of our common units may be lower than other forms of equity ownership because of the absence or reduction of a takeover premium in the trading price.

Enterprise Products GP has a limited call right that may require common unitholders to sell their units at an undesirable time or price.

          If at any time Enterprise Products GP and its affiliates own 85% or more of the common units then outstanding, Enterprise Products GP will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units held by unaffiliated persons at a price not less than the then current market price. As a result, common unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment. They may also incur a tax liability upon a sale of their units.

Our common unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

          Under Delaware law, common unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.

          Under Delaware law, our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our general partner.

          In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a limited partner may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

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

          Shell owns 29,407,549 of our common units, representing approximately 7.5% of our outstanding common units at February 15, 2006, and has publicly announced its intention to reduce its holdings of our common units on an orderly schedule over a period of years, taking into account market conditions. All of the common units held by Shell are registered for resale under our effective registration statement on Form S-3.

          Sales of a substantial number of our common units in the public market could cause the market price of our common units to decline. As of February 22, 2006, we had 390,308,358 common units outstanding. Sales of a substantial number of these common units in the trading markets, whether in a single transaction or series of transactions, or the possibility that these sales may occur, could reduce the market price of our outstanding common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

Tax Risks to Common Unitholders

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

          The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (“IRS”) on this matter.

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

          Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to our common unitholders would be reduced.

A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any contests will be borne by our unitholders and our general partner.

          The IRS may adopt positions that differ from the positions we take, even positions taken with advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be borne indirectly by our unitholders and our general partner.

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

          Common unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Our common unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability which results from their share of our taxable income.

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

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

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

          Investments in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds), and foreign persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Recent legislation treats net income derived from the ownership of certain publicly traded partnerships (including us) as qualifying income to a regulated investment company. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

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

          Because we cannot match transferors and transferees of common units, we adopt depreciation and amortization positions that may not conform with all aspects of applicable Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the common unitholder’s tax returns.

Our common unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of an investment in our common units.

          In addition to federal income taxes, our common unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property. Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, they may by subject to penalties for failure to comply with those requirements. We may own property or conduct business in other states or foreign countries in the future. It is the responsibility of the common unitholder to file all United States federal, state and local tax returns.

The sale or exchange of 50% or more of our capital and profits interests during any twelve- month period will result in the termination of our partnership for federal income tax purposes.

          We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

Item 1B. Unresolved Staff Comments.

          None.

Item 2. Properties.

          The following sections provide information regarding our principal plants, pipelines and other assets by segment. For information regarding our significant historical throughput, production and processing rates, please read Item 7 of this annual report.

          Our real property holdings fall into two basic categories: (i) parcels that we and our unconsolidated affiliates own in fee (e.g., we own the land upon which our Mont Belvieu NGL fractionator is constructed) and (ii) parcels in which our interests and those of our unconsolidated affiliates are derived 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 significant 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 and our unconsolidated affiliates have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our rights pursuant to any material lease, easement, right-of-way, permit or license, and we believe that we have satisfactory rights pursuant to all of our material leases, easements, rights-of-way, permits and licenses.

NGL Pipelines & Services

          The following table summarizes the significant NGL pipelines and related storage assets of our NGL Pipelines & Services business segment at February 1, 2006.

												Useable
				Our								Storage
				Ownership				Length				Capacity
Description of Asset		Location(s)		Interest				(Miles)				(MMBbls)
NGL pipelines: (1)
Mid-America Pipeline System		Midwest and Western U.S.(2)			100	%			7,226
Dixie Pipeline		South and Southeastern U.S.			65.9	% (3)			1,301
Seminole Pipeline		Texas			90	% (4)			1,281
Texas NGL System (5)		Texas			100	%			1,039
Louisiana Pipeline System		Louisiana			Various(6)				655
Promix NGL Gathering System		Louisiana			50	% (7)			410
Houston Ship Channel		Texas			100	%			266
Lou-Tex NGL		Texas, Louisiana			100	%			204
Others (5 systems) (8)		Alabama, Louisiana, Mississippi			Various				427
Total miles									12,809
NGL and related product storage facilities by state:
Texas													114.9
Louisiana													13.0
Mississippi													10.9
Others (Arizona, Georgia, Iowa, Kansas, Nebraska, Oklahoma, Utah)													9.6
Total capacity (9)													148.4

         The following information highlights the general use of each of our principal NGL pipelines. We operate our NGL pipelines with the exception of Tri-States and a small portion of the Louisiana Pipeline System.

§

The Mid-America Pipeline System is a regulated NGL pipeline system consisting of three primary segments: the 2,548-mile Rocky Mountain pipeline, the 2,740-mile Conway North pipeline and

			the 1,938-mile Conway South pipeline. 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 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 connections. The Conway South pipeline connects the Conway hub with Kansas refineries and transports NGLs from Conway, Kansas to the Hobbs hub (with interconnections with our Seminole pipeline at the Hobbs hub). We also own fifteen unregulated propane terminals that are an integral part of the Mid-America Pipeline 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.

	§		The Dixie Pipeline is a regulated propane pipeline extending from southeast 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.
	§		The Seminole Pipeline is a regulated pipeline that transports NGLs from the Hobbs hub and the Permian Basin area to southeastern Texas. The primary source of throughput for the Seminole pipeline is the Mid-America Pipeline 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 NGL fractionation facilities. The pipeline system also includes approximately 660 miles of pipelines that deliver NGLs 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.
	§		The Louisiana Pipeline System is a network of nine NGL pipelines located in Louisiana. This system transports NGLs originating in southern Louisiana and Texas to 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.
	§		The Promix NGL Gathering System is a NGL pipeline system that gathers mixed NGLs from natural gas processing plants in Louisiana for delivery to the Promix NGL fractionator. This gathering system is an integral part of the Promix NGL fractionation facility.
	§		The Houston Ship Channel pipeline system is a collection of pipelines extending from our Houston Ship Channel import/export facility and Morgan’s Point facility to Mont Belvieu, Texas. This system is used to deliver NGL products to third-party petrochemical plants and refineries as well as to deliver feedstocks to our Mont Belvieu facilities.
	§		The Lou-Tex NGL pipeline system is used to provide transportation services for NGLs and refinery grade propylene between the Louisiana and Texas markets. We also use this pipeline to transport mixed NGLs from certain of our Louisiana gas processing plants to our Mont Belvieu NGL fractionation facility.

              Our NGL and related product storage facilities are integral parts of our pipeline and other operations. In general, these underground storage facilities are used to store our and our customers’ NGLs

and petrochemicals. Our underground storage facilities include locations in Arizona, Kansas and Utah that were acquired in July 2005 from Ferrellgas L.P. We operate these facilities, with the exception of certain storage locations operated for us by a third party in Louisiana and Mississippi.

           The following table summarizes the significant natural gas processing and NGL fractionation assets of our NGL Pipelines & Services business segment at February 1, 2006.

								Net Gas				Total Gas				Net				Total
				Our				Processing				Processing				Plant				Plant
				Ownership				Capacity				Capacity				Capacity				Capacity
Description of Asset		Location(s)		Interest				(Bcf/d) (2)				(Bcf/d)				(MBPD)				(MBPD)
Natural gas processing facilities: (1, 3,4)
Toca		Louisiana			60.3	%			0.66				1.10
Chaco (4)		New Mexico			100	%			0.65				0.65
North Terrebonne		Louisiana			44.3	%			0.58				1.30
Yscloskey		Louisiana			31.1	%			0.54				1.85
Calumet		Louisiana			31.5	%			0.50				1.60
Neptune		Louisiana			66	%			0.43				0.65
Pascagoula		Mississippi			40	%			0.40				1.50
Thompsonville (4)		Texas			100	%			0.30				0.30
Shoup (4)		Texas			100	%			0.29				0.29
Gilmore (4)		Texas			100	%			0.26				0.26
Armstrong (4)		Texas			100	%			0.25				0.25
Matagorda (4)		Texas			100	%			0.25				0.25
Others (12 facilities)(4,5)		Texas, New Mexico, Louisiana			Various(6)				1.24				5.38
Total processing capacities									6.35				15.38
NGL fractionation facilities: (7,8)
Mont Belvieu		Texas			75	%											158				210
Norco		Louisiana			100	%											75				75
Promix		Louisiana			50	%											73				145
Shoup		Texas			100	%											69				69
BRF		Louisiana			32.2	%											19				60
Others (4 facilities) (9)		Texas, Louisiana			Various												45				93
Total plant capacities																	439				652

           At the core of our natural gas processing business are twenty-four processing plants located in Texas, Louisiana, Mississippi and New Mexico. Our natural gas processing facilities can be characterized as two distinct types: (i) straddle plants situated on mainline natural gas pipelines owned either by us or by third parties or (ii) field plants that process natural gas in connection with gathering pipelines. We operate the Toca, Chaco, North Terrebonne, Calumet and Neptune plants and all of the Texas facilities.

           Our NGL marketing activities utilize a fleet of approximately 600 railcars, the majority of which are leased. These railcars are used to deliver feedstocks to our facilities and to distribute NGLs throughout the United States. We have rail loading and unloading facilities in Arizona, Kansas, Louisiana, Mississippi and Texas. These facilities service both our rail shipments and those of our customers.

          The following information highlights the general use of each of our principal NGL fractionation facilities. We operate all of our NGL fractionation facilities, with the exception of the facility owned by VESCO.

	§		Our Mont Belvieu NGL fractionation facility is located at Mont Belvieu, Texas, which is a key hub of the domestic and international NGL industry. This 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 Gulf Coast.
	§		The Norco NGL fractionation facility receives mixed NGLs via pipeline from refineries and natural gas processing plants, including our Yscloskey and Toca natural gas processing plants.
	§		The Promix NGL fractionation facility 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 NGL pipelines. In addition to the 410-mile Promix NGL pipeline, Promix owns five NGL storage caverns and a barge loading facility that are integral to its operations.
	§		Our Shoup NGL fractionation facility fractionates mixed NGLs supplied by our South Texas natural gas processing facilities.
	§		The BRF facility processes mixed NGLs from production fields in Alabama, Mississippi and southern Louisiana as well as offshore Gulf of Mexico areas.

            Our NGL operations include import and export facilities located on the Houston Ship Channel in southeast Texas. We lease an import facility that can offload NGLs from tanker vessels at a rate of 10,000 barrels per hour. In addition, we own an export facility that can load cargoes of refrigerated propane and butane onto tanker vessels at rates of up to 5,000 barrels per hour. In addition, we own a barge dock that can load or offload two barges of NGLs or refinery-grade propylene simultaneously at rates up to 5,000 barrels per hour. Our average combined NGL import and export volumes were 119 MBPD, 91 MBPD and 79 MBPD for 2005, 2004 and 2003, respectively.

Onshore Natural Gas Pipelines & Services

          The following table summarizes the significant assets of our Onshore Natural Gas Pipelines & Services business segment at February 1, 2006.

												Approximate
				Our								Capacity,				Gross
				Ownership				Length				Natural Gas				Capacity
Description of Asset		Location(s)		Interest				(Miles)				(MMcf/d)				(Bcf)
Onshore natural gas pipelines:(1)
Texas Intrastate System(2)		Texas			100	%(3)			8,222				4,975
San Juan Gathering System(2)		New Mexico, Colorado			100	%			5,404				1,100
Permian Basin System(2)		Texas, New Mexico			100	%			1,477				490
Acadian Gas System		Louisiana			100	%(4)			1,027				954
Alabama Intrastate System(2)		Alabama			100	%			402				200
Other (4 systems)(5)		Texas, Mississippi			Various(6)				684
Total miles									17,216
Natural gas storage facilities:
Petal(2)		Mississippi			100	%											11.9
Hattiesburg(2)		Mississippi			100	%											4.0
Wilson(2)		Texas			Leased(7)												6.4
Acadian		Louisiana			Leased(8)												3.0
Total gross capacity																	25.3

          The following information highlights the general use of each of our principal onshore natural gas pipelines and storage facilities, all of which we operate.

	§		The Texas Intrastate System gathers and transports natural gas from supply basins in Texas (from both onshore and offshore sources) to local gas distribution companies and electric generation and industrial consumers. This system serves important natural gas producing regions and commercial markets in Texas, including Corpus Christi, the San Antonio/Austin area, the Beaumont/Orange area, and the Houston Ship Channel industrial market. The Texas Intrastate System is comprised of the 7,292-mile GulfTerra Texas Intrastate pipeline system, the 197-mile TPC Offshore gathering system and the 733-mile Channel pipeline system. The Wilson natural gas storage facility is an integral part of the Texas Intrastate System.
	§		The San Juan Gathering System serves natural gas producers in the San Juan Basin of New Mexico and Colorado. This system gathers natural gas production from over 10,450 wells in the San Juan Basin and delivers the natural gas to natural gas processing facilities, including our Chaco facility.
	§		The Permian Basin System gathers natural gas from wells in the Permian Basin region of Texas and New Mexico and delivers natural gas into the El Paso Natural Gas, Transwestern and Oasis pipelines. The Permian Basin System is comprised of the 674-mile Waha system and 803-mile Carlsbad system.

	§		The Acadian Gas System purchases, transports, stores and sells natural gas in Louisiana. The Acadian Gas System is comprised of the 577-mile Cypress pipeline, 423-mile Acadian pipeline and the 27-mile Evangeline pipeline. The Acadian natural gas storage facility is an integral part of the Acadian Gas System.
	§		The Alabama Intrastate System gathers coal bed methane from wells in the Black Warrior Basin in Alabama. This system is also involved in the purchase, transportation and sale of natural gas.
	§		Our Petal and Hattiesburg underground storage facilities are strategically situated to serve the domestic Northeast, Mid-Atlantic and Southeast natural gas markets and are capable of delivering in excess of 1.4 Bcf/d of natural gas into five interstate pipeline systems.

Offshore Pipelines & Services

          The following table summarizes the significant assets of our Offshore Pipelines & Services business segment at February 1, 2006, all of which are located in the Gulf of Mexico primarily offshore Louisiana and Texas.

		Our						Water				Approximate Net Capacity
		Ownership		Length				Depth				Natural Gas				Crude Oil
Description of Asset		Interest		(Miles)				(Feet)				(MMcf/d)				(MPBD)
Offshore natural gas pipelines:(1)
Manta Ray Offshore Gathering System		25.7%(2)			250								206
High Island Offshore System(3)		100%			204								1,800
Viosca Knoll Gathering System(3)		100%			162								1,000
Green Canyon Laterals(3)		Various(4)			136								649
Anaconda Gathering System(3)		100%			136								550
Nautilus System		25.7%(2)			101								154
East Breaks System(3)		100%			85								400
Phoenix Gathering System(3)		100%			78								450
Nemo Gathering System		33.9%(5)			24								102
Falcon Gas Pipeline(3)		100%			14								400
Total miles					1,190
Offshore crude oil pipelines:(6)
Cameron Highway Oil Pipeline(3)		50%(7)			378												250
Poseidon Oil Pipeline System(3)		36%(8)			324												144
Constitution Oil Pipeline		100%			70												80
Allegheny Oil Pipeline(3)		100%			43												140
Marco Polo Oil Pipeline(3)		100%			36												120
Typhoon Oil Pipeline(3)		100%			16												80
Tarantula Oil Pipeline(3)		100%			4												30
Total miles					871
Offshore platforms: (3,9)
Ship Shoal 332A(10)		62%							438
Ship Shoal 332B(10)		50%(7)							438
Marco Polo		50%(11)							4,300				150				60
Viosca Knoll 817		100%							671				140				5
Garden Banks 72		50%							518				40				18
East Cameron 373		100%							441				195				3
Falcon Nest		100%							389				400				3

          The following information highlights the general use of each of our principal Gulf of Mexico offshore natural gas pipelines. We operate our offshore natural gas pipelines, with the exception of the Manta Ray Offshore Gathering System, Nautilus System, Nemo Gathering System and certain components of the Green Canyon Laterals.

	§		The Manta Ray Offshore Gathering 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 System.
	§		The High Island Offshore System (“HIOS”) 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.
	§		The Viosca Knoll Gathering System transports natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas to several major interstate pipelines, including the Tennessee Gas, Columbia Gulf, Southern Natural, Transco, Dauphin Island Gathering System and Destin Pipelines.
	§		The Green Canyon Laterals consist of 28 pipeline laterals (which are extensions of natural gas pipelines) that transport natural gas to downstream pipelines, including the HIOS.
	§		The Anaconda Gathering System connects our Marco Polo platform and Constitution Gas Pipeline to the ANR pipeline system. The Anaconda Gathering System includes our wholly-owned Constitution Gas Pipeline, which was completed in late 2005 and serves the Constitution and Ticonderoga fields located in the central Gulf of Mexico. We initiated flows into our Constitution Gas Pipeline during the first quarter of 2006.
	§		The Nautilus System connects our Manta Ray Offshore Gathering System to our Neptune natural gas processing plant.
	§		The East Breaks System connects the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25 to the HIOS.
	§		The Phoenix Gathering System connects the Red Hawk platform located in the Garden Banks area of the Gulf of Mexico to the ANR pipeline system.
	§		The Nemo Gathering System transports natural gas from Green Canyon developments to an interconnect with our Manta Ray Offshore Gathering System.
	§		The Falcon Gas Pipeline delivers 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.

          The following information highlights the general use of each of our principal Gulf of Mexico offshore crude oil pipelines, all of which we operate.

	§		The Cameron Highway Oil Pipeline, which commenced operations during the first quarter of 2005, gathers crude oil production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in southeast Texas.
	§		The Poseidon Oil Pipeline System gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico for delivery to onshore locations in south Louisiana.

	§		The Constitution Oil Pipeline was completed in late 2005 and serves the Constitution and Ticonderoga fields located in the central Gulf of Mexico. Initial throughput volumes were received during the first quarter of 2006. The Constitution Oil Pipeline connects with our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System at a pipeline junction platform.
	§		The Allegheny Oil Pipeline connects the Allegheny and South Timbalier 316 platforms in the Green Canyon area of the Gulf of Mexico with our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.
	§		The Marco Polo Oil Pipeline gathers crude oil from our Marco Polo platform to an interconnect with our Allegheny Oil Pipeline in Green Canyon Block 164.

         The following information highlights the general use of each of our principal Gulf of Mexico offshore platforms. We operate these offshore platforms with the exception of the Marco Polo platform and East Cameron 373.

	§		The Ship Shoal 332A platform is a junction platform, which serves as a location for crude oil and natural gas to enter our system of assets. Crude oil and natural gas produced in the deepwater Gulf of Mexico is transported to the Ship Shoal 332A platform via several third-party pipelines. Crude oil enters our Poseidon Oil Pipeline System and Allegheny Oil Pipelines at the Ship Shoal 332 A platform, and natural gas enters our Manta Ray Offshore Gathering System.
	§		The Ship Shoal 332B platform is a junction platform for crude oil pipelines. Crude oil produced in the deepwater Gulf of Mexico is transported to the Ship Shoal 332B platform on our Poseidon Oil Pipeline System and Constitution Oil Pipeline and third-party pipelines. The crude oil is then shipped off this platform via our Cameron Highway Oil Pipeline.
	§		The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural gas from the Marco Polo, K2, K2 North and Genghis Khan fields located in the South Green Canyon area of the Gulf of Mexico.
	§		The Viosca Knoll 817 platform is centrally located on our Viosca Knoll Gathering System. This platform primarily serves as a base for gathering deepwater production in the area, including the Ram Powell development.
	§		The Garden Banks 72 platform serves as a base for gathering deepwater production from the Garden Banks Block 161 development and the Garden Banks Block 378 and 158 leases. This platform also serves as a junction platform for our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System.
	§		The East Cameron 373 platform serves as the host for East Cameron Block 373 production and also processes production from Garden Banks Blocks 108, 152, 197, 200 and 201.
	§		The Falcon Nest platform currently processes natural gas from the Falcon field.

Petrochemical Services

          The following table summarizes the significant assets of our Petrochemical Services segment at February 1, 2006.

Net

Total

Our

Plant

Plant

Ownership

Capacity

Capacity

Length

Description of Asset

Location(s)

Interest

(MBPD)

(MBPD)

(Miles)

Propylene fractionation facilities:(1)

Mont Belvieu (3 plants)

Texas

Various(2)

58

72

BRPC

Louisiana

30

%(3)

7

23

Total capacity

65

95

Isomerization facility:

Mont Belvieu(4)

Texas

100

%

116

116

Petrochemical pipelines:(5)

Lou-Tex Propylene

Texas, Louisiana

100

%

291

Lake Charles

Texas, Louisiana

50

%(6)

88

Others (7 systems)(7)

Texas, Louisiana

Various(8)

311

Total miles

690

Octane additive production facilities:

Mont Belvieu

Texas

100

%

(Dual Use)(9)

          We produce polymer grade propylene at our Mont Belvieu facilities and chemical grade propylene at our BRPC facility. The primary purpose of the BRPC unit is to fractionate refinery grade propylene produced by an affiliate of ExxonMobil Corporation into chemical grade propylene. The production of polymer grade propylene from our Mont Belvieu plants is primarily used in our petrochemical marketing activities.

          The Lou-Tex Propylene pipeline is used to transport propylene from Sorrento, Louisiana to Mont Belvieu, Texas. Currently, this pipeline is used to transport chemical grade propylene. This business segment also includes an above-ground polymer grade propylene storage and export facility located in Seabrook, Texas. This facility can load vessels at rates up to 5,000 barrels per hour. We operate all of the assets in our Petrochemical Services business segment.

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 not aware of any significant litigation, pending or threatened, that may have a significant adverse effect on our financial position or results of operations.

          A number of lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing MTBE, although generally such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary that owns the facility. It is possible, however, that MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits. In connection with our purchase of additional equity interests in the owner of the octane-additive production facility in 2003 from an affiliate of Devon Energy Corporation (“Devon”) and in 2004 from an affiliate of Sunoco, Inc. (“Sun”), Devon and Sun indemnified us for any related liability (including liabilities described above) that are in respect of periods prior to the date we purchased such interests. There are no dollar limits or deductibles associated with the indemnities we received from Sun and Devon with respect to potential claims linked to the period of time they held ownership interests in the facility.

Item 4. Submission of Matters to a Vote of Security Holders.

          None.

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 listed on the NYSE under the ticker symbol “EPD.” As of February 15, 2006, there were an estimated 920 unitholders of record of our common units. The following table sets forth the high and low sales prices for our common units during the periods indicated (as reported by the NYSE Composite Transaction Tape) and the amount, record date and payment date of the quarterly cash distributions we paid on each of our common units.

										Cash Distribution History
		Price Ranges								Per				Record		Payment
		High				Low				Unit				Date		Date
2004
1st Quarter		$	24.720			$	21.750			$	0.3725			Apr. 30, 2004		May 12, 2004
2nd Quarter		$	23.840			$	20.000			$	0.3725			Jul. 30, 2004		Aug. 6, 2004
3rd Quarter		$	23.700			$	20.190			$	0.3950			Oct. 29, 2004		Nov. 5, 2004
4th Quarter		$	25.990			$	22.730			$	0.4000			Jan. 31, 2005		Feb. 14, 2005
2005
1st Quarter		$	28.350			$	23.150			$	0.4100			Apr. 29, 2005		May 10, 2005
2nd Quarter		$	27.090			$	24.770			$	0.4200			Jul. 29, 2005		Aug. 10, 2005
3rd Quarter		$	27.660			$	23.500			$	0.4300			Oct. 31, 2005		Nov. 8, 2005
4th Quarter		$	26.020			$	23.380			$	0.4375			Jan. 31, 2006		Feb. 9, 2006

          The quarterly cash distributions shown in the table above correspond to cash flows for the quarters indicated. The actual cash distributions (i.e., the payments made to our partners) occur within 45 days after the end of such quarter. 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 “Liquidity and Capital Resources” included under Item 7 of this annual report. Although the payment of cash dividends is not guaranteed, we expect to continue to pay comparable cash distributions in the future.

Recent Sales of Unregistered Securities

          There were no sales of unregistered equity securities during 2005.

Common Units Authorized for Issuance Under Equity Compensation Plan

          Please read the information included under Item 12 of this annual report, which is incorporated by reference into this Item 5.

Issuer Purchases of Equity Securities

          We did not repurchase any of our common units during 2005. In December 1998, we announced a common unit 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 2-for-1 unit split in May 2002). As of February 15, 2006, we and our affiliates are authorized to repurchase up to 618,400 additional common units under this repurchase program.

Item 6. Selected Financial Data.

           The following table presents selected historical financial data of Enterprise Products Partners. This information has been derived from our audited financial statements for the periods indicated and should be read in conjunction with the audited financial statements included under Item 8 of this annual report. In addition, information regarding our results of operations and liquidity and capital resources can be found under Item 7 of this annual report. As presented in the table, amounts (except per unit data) are in thousands.

		Year Ended December 31,
		2005				2004				2003				2002				2001
Operating results data:(1)
Revenues		$	12,256,959			$	8,321,202			$	5,346,431			$	3,584,783			$	3,154,369
Income from continuing operations(2)		$	423,716			$	257,480			$	104,546			$	95,500			$	242,178
Income per unit from continuing operations:(3)
Basic		$	0.92			$	0.83			$	0.42			$	0.55			$	1.70
Diluted		$	0.92			$	0.83			$	0.41			$	0.48			$	1.39
Other financial data:
Distributions per common unit(4)		$	1.698			$	1.540			$	1.470			$	1.360			$	1.194
Commodity hedging income (loss)(5)		$	1,095			$	448			$	(619	)		$	(51,344	)		$	101,290

		As of December 31,
		2005				2004				2003				2002				2001
Financial position data:(1)
Total assets		$	12,591,016			$	11,315,461			$	4,802,814			$	4,230,272			$	2,424,692
Long-term and current maturities of debt(6)		$	4,833,781			$	4,281,236			$	2,139,548			$	2,246,463			$	855,278
Partners’ equity(7)		$	5,679,309			$	5,328,785			$	1,705,953			$	1,200,904			$	1,146,922
Total units outstanding (excluding treasury)(7)			389,861				364,786				217,780				183,810				174,542

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

For the years ended December 31, 2005, 2004 and 2003.

          Enterprise Products Partners L.P. is a North American midstream energy company that provides a wide range of services to producers and consumers of natural gas, natural gas liquids (“NGLs”), and crude oil, and is an industry leader in the development of pipeline and other midstream assets in the continental United States and Gulf of Mexico. Unless the context requires otherwise, references to “we,” “us,” “our,” or “Enterprise Products Partners” are intended to mean the consolidated business and operations of Enterprise Products Partners L.P. and its subsidiaries.

          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 Products GP”). Enterprise Products GP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded affiliate listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPE.” We, Enterprise Products GP and Enterprise GP Holdings are affiliates and under common control of Dan L. Duncan, the Chairman and the controlling shareholder of EPCO, Inc. (“EPCO”).

          This annual report contains various forward-looking statements and information based on our beliefs and those of Enterprise Products GP, as well as assumptions made by us and information currently available to us. Please read the section titled “Cautionary Statement Regarding Forward-Looking Information” included under Item 1 of this annual report.

          As generally used in the energy industry and in this document, the identified terms have the following meanings:

	/ d		= per day
	BBtus		= billion British Thermal units
	Bcf		= billion cubic feet
	MBPD		= thousand barrels per day
	Mdth		= thousand dekatherms
	MMBbls		= million barrels
	MMBtus		= million British thermal units
	MMcf		= million cubic feet
	Mcf		= thousand cubic feet

RECENT DEVELOPMENTS

          The year 2005 was a challenging year for Enterprise Products Partners. The Gulf Coast region experienced two major hurricanes (Katrina and Rita) that affected our employees, suppliers, customers and industry. Our thoughts remain with those displaced by these storms and we are well-positioned to assist the Gulf Coast energy industry in the rebuilding effort. Although certain of our facilities incurred structural damage as a result of the storms and other operations were interrupted, by year-end the majority of our operated facilities were at pre-hurricane production, transportation or processing levels. In particular, our Toca natural gas processing facility, which is located in coastal Louisiana and was heavily damaged in Hurricane Katrina, has recently returned to operations. For information regarding our insurance claims related to these storms, please read Note 22 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          Our growth capital spending for 2005 was a record of $743.8 million, which includes $338.6 million for our Independence Hub offshore platform and related Independence Trail Pipeline and $90.1 million for our Constitution Oil and Constitution Gas Pipelines. In addition, we recently announced two new natural gas processing projects in the Rockies. We expect that these projects will enhance our existing asset base and provide us with additional growth opportunities in the future. In addition to our growth capital projects, we completed $326.6 million in acquisitions during 2005, the largest of which was the $145.5 million purchase of underground NGL storage facilities and propane terminals from Ferrellgas L.P.

(“Ferrellgas”). For additional information regarding our growth capital spending and acquisitions, please read “Capital Spending” included within this Item 7.

          During 2005, we completed the integration of our legacy operations with those of GulfTerra Energy Partners L.P. (“GulfTerra”). In September 2004, we completed the “GulfTerra Merger” transaction, whereby GulfTerra merged with one of our wholly owned subsidiaries. As a result of the GulfTerra Merger, GulfTerra and its subsidiaries and GulfTerra’s general partner (“GulfTerra GP”) became our wholly owned subsidiaries. The GulfTerra Merger greatly expanded our asset base to include numerous natural gas and crude oil pipelines, offshore platforms and other midstream energy assets. Additionally, the GulfTerra Merger included the purchase of various midstream assets from El Paso that are located in South Texas. For additional information regarding the GulfTerra Merger, please read Note 12 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          Our Cameron Highway Oil Pipeline began deliveries of Gulf of Mexico crude oil production during the first quarter of 2005 to major refining markets along the Texas Gulf Coast. The Cameron Highway Oil Pipeline can transport up to 500 MBPD of deepwater Gulf of Mexico crude oil production. We own a 50% interest in this system through our equity method investment in Cameron Highway Oil Pipeline Company (“Cameron Highway”).

          We completed construction of the Constitution Oil and Constitution Gas Pipelines in 2005. We own and operate these pipelines, which provide production gathering services for the Constitution and Ticonderoga fields in the Gulf of Mexico. Initial throughput is expected on the Constitution pipelines during the first quarter of 2006.

          In May 2003, GulfTerra commenced a project relating to its San Juan Basin assets. The San Juan Optimization Project was substantially complete in 2005 at an approximate cost of $31 million. This project resulted in a 10% increase of capacity on our San Juan Gathering System and will increase market opportunities through a new interconnect with the Transwestern Pipeline. We connected a record 336 natural gas wells to the San Juan Gathering System during 2005.

          In February 2005, we sold 17,250,000 common units (including an over-allotment amount of 2,250,000 common units which closed in March 2005), which generated net proceeds of approximately $456.7 million. In addition, our Operating Partnership sold $500 million of senior notes in February 2005. In March 2005, we filed a universal shelf registration statement with the SEC registering the issuance of up to $4 billion of additional partnership equity and/or public debt obligations. In June 2005, our Operating Partnership sold $500 million of senior notes under this registration statement. In December 2005, we sold 4,000,000 common units under this registration statement, which generated net proceeds of $98.7 million. For additional information regarding our debt obligations and capital structure, please see Notes 14 and 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          In October 2005, our Operating Partnership amended its revolving credit facility to increase total bank commitments from $750 million to $1.25 billion (which may be further increased to $1.4 billion upon our request, subject to certain conditions). The increase in borrowing capacity under our Multi-Year Revolving Credit Facility further enables us to meet future funding requirements of our growth capital projects. For additional information regarding our debt obligations, please see Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          The ownership of our general partner underwent a number of changes during 2005. In January 2005, affiliates of EPCO acquired a 9.9% membership interest in Enterprise Products GP and 13,454,498 of our common units from El Paso for approximately $425 million in cash. As a result of these transactions, EPCO and its affiliates owned 100% of the membership interests of Enterprise Products GP. In August 2005, EPCO and its affiliates contributed their membership interests in Enterprise Products GP to Enterprise GP Holdings. Affiliates of EPCO currently own 86.5% of Enterprise GP Holdings. For additional information regarding these transactions between related parties, please read Item 13 of this annual report.

CAPITAL SPENDING

          We are committed to the long-term growth and viability of Enterprise Products Partners. Part of our business strategy involves expansion through business combinations, growth capital projects and investments in joint ventures. In recent years, major oil and gas companies have sold non-strategic assets in the midstream energy sector in which we operate. We forecast that this trend will continue, and expect independent oil and natural gas companies to consider similar divestitures. Management continues to analyze potential acquisitions, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions.

          We believe that we are positioned to continue to grow through construction of new facilities and acquisitions that will expand our system of assets and through growth capital projects. We estimate our consolidated capital spending during 2006 will approximate $1.8 billion, which includes estimated expenditures of approximately $1.7 billion for growth capital projects and acquisitions and approximately $78 million for sustaining capital expenditures.

          Our forecast of consolidated capital expenditures is based upon our strategic operating and growth plans, which are also dependent upon our ability to generate capital from operating cash flows or otherwise obtain the capital necessary to accomplish our objectives. Our forecast may change due to factors beyond our control, such as weather related issues, changes in supplier prices or adverse economic conditions. Further, our forecast may change as a result of decisions made at a later date, which may include acquisitions or decisions to take on additional partners.

          Our success in raising capital, including the formation of joint ventures to share costs and risks, continues to be the principal factor that determines how much we can spend. We believe our access to capital resources is sufficient to meet the demands of our current and future operating growth needs, and although we currently intend to make the forecasted expenditures discussed above, we may adjust the timing and amounts of projected expenditures in response to changes in capital markets.

          The following table summarizes our capital spending by activity for the periods indicated (dollars in thousands):

		For Year Ended December 31,
		2005				2004				2003
Capital spending for business combinations and asset purchases:
GulfTerra Merger:
Cash payments to El Paso, including amounts paid to acquire certain South Texas midstream assets						$	655,277
Transaction fees and other direct costs							24,032
Cash received from GulfTerra							(40,313	)
Net cash payments							638,996
Value of non-cash consideration issued or granted							2,910,771
Total GulfTerra Merger consideration							3,549,767
Indirect interests in the Indian Springs natural gas gathering and processing assets		$	74,854
Additional ownership interests in Dixie Pipeline Company (“Dixie”)			68,608
NGL underground storage and terminalling assets purchased from Ferrellgas			145,522
Other business combinations and asset purchases			37,618				85,851			$	37,348
Total			326,602				3,635,618				37,348
Capital spending for property, plant and equipment:
Growth capital projects, net			743,827				114,419				125,600
Sustaining capital projects			73,622				32,509				20,313
Total			817,449				146,928				145,913
Capital spending attributable to unconsolidated affiliates:
Purchase of 50% interest in GulfTerra GP in connection with the initial step of the GulfTerra Merger											425,000
Other investments in and advances to unconsolidated affiliates			88,044				64,412				46,927
Total			88,044				64,412				471,927
Total capital spending		$	1,232,095			$	3,846,958			$	655,188

          As shown in the preceding table, capital spending for growth capital projects is presented net of contributions in aid of construction costs of $47 million, $8.9 million and $0.9 million during 2005, 2004 and 2003, respectively. On certain of our capital projects, third parties may be obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins.

          Our significant capital spending transactions during 2005 include the following:

§		We paid El Paso $74.9 million for indirect majority ownership interests in the 89-mile Indian Springs Gathering System and the Indian Springs natural gas processing facility, both of which are located in East Texas.
§		We paid $68.6 million for an additional 46% interest in Dixie from affiliates of ConocoPhillips and ChevronTexaco. As a result of these acquisitions, Dixie is now a majority-owned consolidated subsidiary of ours.
§		We purchased three NGL underground storage facilities and four propane terminals from Ferrellgas for $145.5 million in cash. The underground storage facilities are located in Kansas, Arizona and Utah and have a combined capacity of 6.1 MMBbls. Approximately 70% of the aggregate storage capacity is leased to third party customers under fee-based contracts. The four propane terminals are located in Minnesota and North Carolina. The Minnesota facilities are connected to our Mid-America Pipeline System, and the North Carolina terminals are connected by rail to our facilities on the Gulf Coast. As part of the transaction, Ferrellgas has contracted with us to maintain a certain level of storage volume and terminal throughput for five years with the option to extend for an additional five years.

Significant Recently Announced Growth Capital Projects

47

          Expansion of Mont Belvieu NGL and Petrochemical Storage Services. In November 2005, we announced an expansion of our NGL and petrochemical storage services at our complex in Mont Belvieu, Texas to improve our ability to receive and deliver NGLs and petrochemicals. The Mont Belvieu expansion projects include the drilling of two new brine production wells and the construction of two above-ground brine storage pits. The increased brine storage capability will further enable us to enhance product storage services and movement to transportation and distribution pipelines that serve the Gulf Coast region, as well as our import and export facilities on the Houston Ship Channel. As a result of these projects, we will also more than double our above-ground brine storage capabilities to 19 MMBbls and will increase our capacity to produce brine. These projects are expected to be placed in service in 2006 and 2007 and are expected to cost $77 million.

          Hobbs NGL Fractionator. In June 2005, we announced plans to construct a new NGL fractionator, designed to handle up to 75 MBPD of mixed NGLs, located at the interconnection of our Mid-America Pipeline System and our Seminole Pipeline near Hobbs, New Mexico. Additionally, we will construct a purity ethane storage well near the new fractionator and reconfigure the interconnection between our Mid-America Pipeline System and the Seminole Pipeline. These projects are expected to cost $175 million and be placed in service by mid-2007. Our Hobbs NGL fractionator will process the increase in mixed NGLs resulting from our Phase I expansion of the Mid-America Pipeline System.

          Mid-America Pipeline System Phase I Expansion. In January 2005, we announced an expansion of the Rocky Mountain segment of our Mid-America Pipeline System to accommodate an expected increase in mixed NGLs originating from producing basins in Wyoming, Utah, Colorado and New Mexico. The expansion project will be completed in stages and will increase throughput volumes on the segment by a total of 50 MBPD. We expect final completion of the Phase I expansion during the second quarter of 2007 at a cost of $187 million. We expect to receive the necessary regulatory approval and begin construction on our Phase I expansion project in the first quarter of 2006.

          Expansion of Mont Belvieu NGL Fractionator. In January 2005, we began a project to expand the processing capacity of our Mont Belvieu NGL fractionator from 210 MBPD to 225 MBPD and to reduce energy costs. This expansion project will enable us to accommodate a portion of an expected increase in NGL production from the Rocky Mountains. The project is expected to cost approximately $41 million and be completed in mid-2006.

          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, Lloyd Ridge and Mississippi Canyon areas (collectively, the “anchor fields”) of the deepwater Gulf of Mexico. First production is expected in 2007.

          We are constructing and will own the Independence Hub platform, which will be located in Mississippi Canyon Block 920, at a water depth of 8,000 feet. The Independence Hub is a 105-foot deep-draft, semi-submersible platform with a two-level production deck, which will process 1 Bcf/d of natural gas. The platform, which is estimated to cost $420 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 International Inc. (“Cal Dive”) to sell them a 20% indirect interest in the Independence Hub platform.

          Additionally, we will construct, own, and operate the 134-mile Independence Trail natural gas pipeline system, which will have a throughput capacity of 1 Bcf/d of natural gas. The pipeline system, which is estimated to cost $268 million, will transport production from the Independence Hub platform to the Tennessee Gas Pipeline.

Pipeline Integrity Costs

          Our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs administered by the U.S. Department of Transportation, through its Office of Pipeline Safety. This federal

agency has issued safety regulations containing requirements for the development of integrity management programs for hazardous liquid pipelines (which include NGL and petrochemical pipelines) and natural gas pipelines. In general, these regulations require companies to assess the condition of their pipelines in certain high consequence areas (as defined by the regulation) and to perform any necessary repairs. In connection with the regulations for hazardous liquid pipelines, we developed a pipeline integrity management program in 2002. In connection with the regulations for natural gas pipelines, we developed a pipeline integrity management program in 2004.

          During 2005, we spent approximately $42.2 million to comply with these programs, of which $25 million was recorded as an operating expense, and the remaining $17.2 million was capitalized. We spent approximately $22.4 million to comply with these programs during 2004, of which $14.9 million was recorded as an operating expense and the remaining $7.5 million was capitalized.

          We expect our net cash outlay for pipeline integrity program expenditures to approximate $63.2 million during 2006. Our forecast is net of certain costs we expect to recover from El Paso. In April 2002, GulfTerra acquired several midstream assets located in Texas and New Mexico from El Paso. These assets include the Texas Intrastate System and the Permian Basin System. El Paso agreed to indemnify GulfTerra for any pipeline integrity costs it incurred (whether paid or payable) during 2005, 2006 and 2007 with respect to such assets, to the extent that such annual costs exceed $3.3 million; however, the aggregate amount reimbursable by El Paso for these periods is capped at $50.2 million. During 2006, we expect to recover $13.8 million from El Paso related to our 2005 expenditures, which leaves a remainder of $36.4 million reimbursable by El Paso for 2006 and 2007 pipeline integrity costs.

RESULTS OF OPERATIONS

          We have four reportable business segments: NGL Pipelines & Services, Onshore Natural Gas Pipelines & Services, Offshore Pipelines & Services and Petrochemical Services. Our business segments are generally organized and managed according to the type of services rendered (or technology employed) and products produced and/or sold.

          We evaluate segment performance based on the non-generally accepted accounting principle (“non-GAAP”) financial measure of gross operating margin. Gross operating margin (either in total or by individual segment) is an important performance measure of the core profitability of our operations. This measure forms the basis of our internal financial reporting and is used by senior management in deciding how to allocate capital resources among business segments. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating segment results. The financial measure calculated using accounting principles generally accepted in the United States of America (“GAAP”) 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: (i) depreciation and amortization expense; (ii) operating lease expenses for which we do not have the payment obligation; (iii) gains and losses on the sale of assets; and (iv) 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 intersegment and intrasegment transactions.

          For additional information regarding our business segments, please read Note 17 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          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 in 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 investments are present within our integrated midstream asset system. For example, we have ownership interests in several offshore natural gas and crude oil pipelines. 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 11 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Selected Price and Volumetric Data

          The following table illustrates selected average quarterly industry index prices for natural gas, crude oil and selected NGL and petrochemical products since the beginning of 2003:

																														Polymer				Refinery
		Natural																Normal								Natural				Grade				Grade
		Gas,				Crude Oil,				Ethane,				Propane,				Butane,				Isobutane,				Gasoline,				Propylene,				Propylene,
		$/MMBtu				$/barrel				$/gallon				$/gallon				$/gallon				$/gallon				$/gallon				$/pound				$/pound
		(1)				(2)				(1)				(1)				(1)				(1)				(1)				(1)				(1)
2003
1st Quarter		$	6.58			$	34.12			$	0.43			$	0.65			$	0.76			$	0.80			$	0.85			$	0.24			$	0.21
2nd Quarter		$	5.40			$	29.04			$	0.39			$	0.53			$	0.58			$	0.62			$	0.65			$	0.25			$	0.19
3rd Quarter		$	4.97			$	30.21			$	0.37			$	0.56			$	0.67			$	0.68			$	0.73			$	0.21			$	0.15
4th Quarter		$	4.58			$	31.18			$	0.40			$	0.58			$	0.73			$	0.71			$	0.75			$	0.22			$	0.16
Average for Year		$	5.38			$	31.14			$	0.40			$	0.58			$	0.68			$	0.70			$	0.74			$	0.23			$	0.18
2004
1st Quarter		$	5.69			$	35.25			$	0.43			$	0.66			$	0.76			$	0.76			$	0.87			$	0.29			$	0.26
2nd Quarter		$	6.00			$	38.34			$	0.45			$	0.65			$	0.79			$	0.79			$	0.92			$	0.32			$	0.26
3rd Quarter		$	5.75			$	43.90			$	0.52			$	0.79			$	0.92			$	0.92			$	1.05			$	0.32			$	0.27
4th Quarter		$	7.07			$	48.31			$	0.60			$	0.85			$	1.03			$	1.04			$	1.15			$	0.40			$	0.35
Average for Year		$	6.13			$	41.45			$	0.50			$	0.74			$	0.88			$	0.88			$	1.00			$	0.33			$	0.29
2005
1st Quarter		$	6.27			$	49.68			$	0.52			$	0.79			$	0.98			$	1.00			$	1.14			$	0.45			$	0.39
2nd Quarter		$	6.74			$	53.09			$	0.52			$	0.82			$	0.98			$	1.01			$	1.16			$	0.37			$	0.30
3rd Quarter		$	8.53			$	63.08			$	0.69			$	0.97			$	1.14			$	1.26			$	1.36			$	0.37			$	0.33
4th Quarter		$	13.00			$	60.03			$	0.76			$	1.06			$	1.27			$	1.34			$	1.36			$	0.50			$	0.44
Average for Year		$	8.64			$	56.47			$	0.62			$	0.91			$	1.09			$	1.15			$	1.26			$	0.42			$	0.37