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, 2006

OR

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

For the transition period from                      to                     .

Commission file number: 1-14323

ENTERPRISE PRODUCTS PARTNERS L.P.

(Exact name of Registrant as Specified in Its Charter)

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

1100 Louisiana, 10th Floor, Houston, Texas				77002
(Address of Principal Executive Offices)				(Zip Code)

(713) 381-6500

(Registrant’s Telephone Number, Including Area Code)

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

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, 2006, 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, 2006, was approximately $6.6 billion. This figure excludes common units beneficially owned by certain affiliates, including (i) Dan L. Duncan, (ii) Enterprise GP Holdings L.P. and (iii) certain trusts established for the benefit of Mr. Duncan’s family. There were 432,408,430 common units of EPD outstanding at February 1, 2007.

 

 

ENTERPRISE PRODUCTS PARTNERS L.P.
TABLE OF CONTENTS

		Page
		Number
PART I
Items 1 and 2. Business and Properties			2
Item 1A. Risk Factors			30
Item 1B. Unresolved Staff Comments			47
Item 3. Legal Proceedings			48
Item 4. Submission of Matters to a Vote of Security Holders			49
PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities			50
Item 6. Selected Financial Data			51
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			52
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			89
Item 8. Financial Statements and Supplementary Data			92
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			92
Item 9A. Controls and Procedures			93
Item 9B. Other Information			98
PART III
Item 10. Directors, Executive Officers and Corporate Governance			98
Item 11. Executive Compensation			106
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters			113
Item 13. Certain Relationships and Related Transactions, and Director Independence			116
Item 14. Principal Accountant Fees and Services			128
PART IV
Item 15. Exhibits and Financial Statement Schedules			129
Signatures			136
Financial Statements			F-1
Third Amendment to Multi-Year Revolving Credit Agreement
Amendment No. 1 to the Fourth Amended and Restated Administrative Services Agreement
Agreement and Limited Partnership
Computation of Ratio of Earnings to Fixed Charges
List of Subsidiaries
Consent of Deloitte & Touche LLP
Section 302 Certification
Section 302 Certification
Section 1350 Certification
Section 1350 Certification

SIGNIFICANT RELATIONSHIPS REFERENCED IN THIS
ANNUAL REPORT

     Unless the context requires otherwise, references to “we,” “us,” “our” or “Enterprise Products Partners” are intended to mean the business and operations of Enterprise Products Partners L.P. and its consolidated subsidiaries, including Duncan Energy Partners.

     References to “Operating Partnership” mean Enterprise Products Operating L.P., which is a wholly owned subsidiary of Enterprise Products Partners through which Enterprise Products Partners conducts substantially all of its business.

     References to “Duncan Energy Partners” or “DEP” mean Duncan Energy Partners L.P., which is a publicly traded, consolidated subsidiary of the Operating Partnership and completed its initial public offering in February 2007.

     References to “Enterprise Products GP” mean Enterprise Products GP, LLC, which is our general partner.

     References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded Delaware limited partnership, which owns Enterprise Products GP.

     References to “EPE Holdings” mean EPE Holdings, LLC, which is the general partner of Enterprise GP Holdings.

     References to “TEPPCO” mean TEPPCO Partners, L.P.; a publicly traded Delaware limited partnership, which is an affiliate of us.

     References to “TEPPCO GP” mean Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and owned by a private company subsidiary of EPCO, Inc.

     References to “EPCO” mean EPCO, Inc., which is a related party affiliate to all of the foregoing named entities.

     References to “Employee Partnerships” mean EPE Unit L.P. and EPE Unit II, L.P., collectively, which are private company affiliates of EPCO. References to “EPE Unit I” and “EPE Unit II” refer to EPE Unit L.P. and EPE Unit II, L.P., respectively.

     We, the Operating Partnership, Duncan Energy Partners, Enterprise Products GP, Enterprise GP Holdings, EPE Holdings, TEPPCO and TEPPCO GP are affiliates and under common control of Dan L. Duncan, the Chairman and controlling shareholder of EPCO.

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 our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner 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.

PART I

Items 1 and 2. Business and Properties.

General

     We are a North American midstream energy company providing a wide range of services to producers and consumers of natural gas, natural gas liquids (“NGLs”), crude oil, and certain petrochemicals. In addition, we are an industry leader in the development of pipeline and other midstream energy infrastructure in the continental United States and Gulf of Mexico. We conduct substantially all of our business through our Operating Partnership. Our principal executive offices are located at 1100 Louisiana, 10^th Floor, Houston, Texas 77002 and our telephone number is (713) 381-6500.

     We are a publicly traded Delaware limited partnership formed in 1998, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” We are owned 98% by our limited partners and 2% by our general partner, Enterprise Products GP. Our general partner is owned by a publicly traded affiliate, Enterprise GP Holdings, the common units of which are listed on the NYSE under the ticker symbol “EPE.”

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

     In September 2006, we formed Duncan Energy Partners, a Delaware limited partnership, to acquire, own and operate a diversified portfolio of midstream energy assets from us. Duncan Energy Partners completed its initial public offering of 14,950,000 common units in February 2007. The common units of Duncan Energy Partners are listed on the NYSE under the ticker symbol “DEP.” For additional information regarding Duncan Energy Partners, see “Recent Developments” within this Item 1.

Business Strategy

     We operate an integrated network of midstream energy assets that includes natural gas gathering, processing, transportation and storage; NGL fractionation (or separation), transportation, storage and import and export terminalling; crude oil transportation; offshore production platform services; and petrochemical pipeline and services. NGL products (ethane, propane, normal butane, isobutane and natural gasoline) are used as raw materials by the petrochemical industry, as feedstocks by refiners in the production of motor gasoline and as fuel by industrial and residential users. 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, U.S. Gulf Coast 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, including those that will provide the raw materials for these growth projects or purchase the project’s end products; and
	§		increase fee-based cash flows by investing in pipelines and other fee-based businesses.

     As noted above, 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, see “Capital Spending” included under Item 7 of this annual report.

Financial Information by Business Segment

     For information regarding our business segments, see Note 16 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Recent Developments

     In September 2006, we formed a consolidated subsidiary, Duncan Energy Partners, to acquire, own and operate a diversified portfolio of midstream energy assets. On February 5, 2007, this subsidiary completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of $291.3 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of these net proceeds to us along with $198.9 million in borrowings under its credit facility and a final amount of 5,371,571 common units of Duncan Energy Partners. Duncan Energy Partners used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,510 common units it had originally issued to Enterprise Products Partners, resulting in the final amount of 5,371,571 common units beneficially owned by Enterprise Products Partners. We used the cash received from Duncan Energy Partners to temporarily reduce amounts outstanding under our Multi-Year Revolving Credit Facility.

     In summary, we contributed 66% of our equity interests in the following subsidiaries to Duncan Energy Partners:

	§		Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”), a recently formed subsidiary, which owns salt dome storage caverns located in Mont Belvieu, Texas that receive, store and deliver NGLs and certain petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States;
	§		Acadian Gas, LLC (“Acadian Gas”), which owns an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. A subsidiary of Acadian Gas owns a 49.5% equity interest in Evangeline Gas Pipeline, L.P. (“Evangeline”);
	§		Sabine Propylene Pipeline L.P. (“Sabine Propylene”), which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana;
	§		Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”), which transports chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas; and
	§		South Texas NGL Pipelines, LLC (“South Texas NGL”), a recently formed subsidiary, which began transporting NGLs from Corpus Christi, Texas to Mont Belvieu, Texas in January 2007. South Texas NGL owns the DEP South Texas NGL Pipeline System.

     In addition, to the 34% ownership interest we retained in each of these entities, we also own the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units. Our Operating Partnership directs the business operations of Duncan Energy Partners through its ownership and control of the general partner of Duncan Energy Partners.

     The formation of Duncan Energy Partners had no effect on our financial statements at December 31, 2006. For financial reporting purposes, the consolidated financial statements of Duncan Energy Partners will be consolidated into those of our own. Consequently, the results of operations of Duncan Energy Partners will be a component of our business segments. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners will reflect our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners.

     The public owners of Duncan Energy Partners’ common units will be presented as a noncontrolling interest in our consolidated financial statements beginning in February 2007. The public owners of Duncan Energy Partners have no direct equity interests in us as a result of this transaction. The borrowings of Duncan Energy Partners will be presented as part of our consolidated debt; however, we do not have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

     We have significant involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions:

	§		We utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses;
	§		We buy natural gas from and sell natural gas to Acadian Gas in connection with our normal business activities; and
	§		We are the sole shipper on the DEP South Texas NGL Pipeline System.

     We may contribute other equity interests in our subsidiaries to Duncan Energy Partners in the near term and use the proceeds we receive from Duncan Energy Partners to fund our capital spending program. We have no obligation or commitment to make such contributions to Duncan Energy Partners.

     For information regarding our other recent developments, see “Overview of Business – Recent Developments” included under Item 7 of this annual report, which is incorporated by reference into this Item 1.

     For recent developments involving releases of ammonia from a third-party pipeline operated by the Operating Partnership through an indirect wholly owned subsidiary, see Item 3 of this annual report.

Segment Discussion

     Our midstream energy 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:

	§		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 technologies 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, see Item 1A 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, safety and other matters. For a discussion of the principal effects such laws and regulations have on our business, see “Regulation” and “Environmental and Safety Matters” included within this Item 1.

     Our revenues are derived from a wide customer base. During 2006 and 2005, our largest customer was The Dow Chemical Company and its affiliates, which accounted for 6.1% and 6.8%, respectively, of our consolidated revenues. During 2004, our largest customer was Shell Oil Company and its affiliates (“Shell”), which accounted for 6.5% of our consolidated revenues.

     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 decatherms
		MMBbls		=		million barrels
		MMBtus		=		million British thermal units
		MMcf		=		million cubic feet
		Mcf		=		thousand cubic feet
		TBtu		=		trillion British thermal units

     The following discussion of our business segments provides information regarding our principal plants, pipelines and other assets. For information regarding our results of operations, including significant measures of historical throughput, production and processing rates, see Item 7 of this annual report.

NGL Pipelines & Services

     Our NGL Pipelines & Services business segment includes our (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines aggregating approximately 13,295 miles and related storage facilities including our Mid-America Pipeline System 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 23 processing plants located in Texas, Louisiana, Mississippi, New Mexico and Wyoming. 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 petrochemical and motor gasoline production 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 natural gas processing plants are higher than the incremental value of the NGL products that would be extracted from a stream of natural gas, 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 sale of the mixed NGLs we extract on the producer’s 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 earn and take title to 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 13,295 miles of NGL pipelines, 162 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 charge customers monthly storage reservation fees to reserve a specific storage capacity in our underground caverns. The customers pay reservation fees based on the quantity of capacity reserved rather than on the amount of reserved capacity utilized. When a customer exceeds its reserved capacity, we charge those customers an excess storage fee. In addition, we charge our customers throughput fees based on volumes injected and withdrawn from the storage facility. Accordingly, the profitability of our storage operations is dependent upon the level of capacity reserved by our customers, the volume of product injected and withdrawn from our underground caverns 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 for delivery 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 payments. 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 seven 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.

     Extraction of mixed NGLs by natural 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 fee-based customers generally retain title to the NGLs that we process for them.

     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 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.

     Properties. The following table summarizes the significant NGL pipelines and related storage assets of our NGL Pipelines & Services business segment at February 5, 2007.

Our

Storage

Ownership

Length

Capacity

Description of Asset

Location(s)

Interest

(Miles)

(MMBbls)

NGL pipelines:

Mid-America Pipeline System

Midwest and Western U.S.

100%

7,378

Dixie Pipeline

South and Southeastern U.S.

74.2%(1)

1,370

Seminole Pipeline

Texas

90% (2)

1,326

EPD South Texas NGL System

Texas

100%

1,039

Louisiana Pipeline System

Louisiana

Various(3)

612

Promix NGL Gathering System

Louisiana

50%

362

DEP South Texas NGL Pipeline System

Texas

100%(4)

286

Houston Ship Channel

Texas

100%

266

Lou-Tex NGL

Texas, Louisiana

100%

204

Others (5 systems) (5)

Alabama, Louisiana, Mississippi

Various

452

Total miles

13,295

NGL and related product storage facilities by state:

Texas (6)

125.0

Louisiana

16.6

Mississippi

10.9

Others (Arizona, Georgia, Iowa, Kansas, Nebraska, Oklahoma, Utah)

9.6

Total capacity (7)

162.1

     The maximum number of barrels that our NGL pipelines can transport per day depends upon the operating balance achieved at a given point in time between various segments of the systems. Since the operating balance is dependent upon the mix of products to be shipped and demand levels at various delivery points, the exact capacities of our NGL pipelines cannot be determined. We measure the utilization rates of such pipelines in terms of net throughput (i.e., on a net basis in accordance with our ownership interest). Total net throughput volumes for these pipelines were 1,450 MBPD, 1,360 MBPD and 1,343 MBPD during the years ended December 31, 2006, 2005 and 2004, respectively.

     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 2,568-mile Rocky Mountain pipeline, the 2,771-mile Conway North pipeline and the 2,039-mile Conway South pipeline. This system covers thirteen states: Wyoming, Utah, Colorado, New Mexico, Texas, Oklahoma, Kansas, Missouri, Nebraska, Iowa, Illinois, Minnesota and Wisconsin. The Rocky Mountain pipeline transports mixed NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to the Hobbs hub located on the Texas-New Mexico border. The Conway North segment links the 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. The Mid-America Pipeline System interconnects 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.
			During 2006, approximately 54% of the volumes transported on the Mid-America Pipeline System were 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 Greater 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. This system operates in seven states: Texas, Louisiana, Mississippi, Alabama, Georgia, South Carolina and North Carolina.
	§		The Seminole Pipeline is a regulated pipeline that transports NGLs from the Hobbs hub and the Permian Basin area of west Texas to markets in southeastern Texas. NGLs originating on the Mid-America Pipeline System are the primary source of throughput for the Seminole Pipeline.
	§		The EPD South 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 between Corpus Christi and Houston, Texas and within the Texas City-Houston area, as well as to common carrier NGL pipelines.
	§		The Louisiana Pipeline System is a network of 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 an NGL fractionator owned by K/D/S Promix, L.L.C. (“Promix”). This gathering system is an integral part of the Promix NGL fractionation facility. Our ownership interest in this pipeline is held indirectly through our equity method investment in Promix.
	§		The DEP South Texas NGL Pipeline System transports NGLs from our Shoup and Armstrong fractionation facilities in south Texas to Mont Belvieu, Texas. This system became operational in January 2007. We purchased 220 miles of this pipeline from ExxonMobil Pipeline Company in August 2006. In addition, we lease an 11-mile segment of this pipeline system from TEPPCO. The remaining 55 miles of this pipeline were either acquired from TEPPCO (10 miles) or constructed by us (45 miles).
			We contributed a direct 66% equity interest in South Texas NGL, our subsidiary that owns the DEP South Texas NGL Pipeline System, to Duncan Energy Partners on February 5, 2007. We own the remaining 34% direct interest in South Texas NGL. For additional information regarding this subsequent event, see “Recent Developments” within this Item 1.
	§		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.

     In addition to the pipelines identified above, we have begun construction on the Meeker pipeline in the Piceance Basin area of western Colorado. This new 50-mile pipeline will transport mixed NGLs from our Meeker natural gas processing facility to the Mid-America Pipeline System.

     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 NGLs and petrochemical products for us and our customers. Our underground storage facilities include locations in Arizona, Kansas and Utah that were acquired in July 2005. We operate these facilities, with the exception of certain storage locations operated for us by a third party in Louisiana and Mississippi.

     We contributed a direct 66% equity interest in our recently formed subsidiary, Mont Belvieu Caverns, to Duncan Energy Partners on February 5, 2007. We own the remaining 34% direct interest in Mont Belvieu Caverns.

     Mont Belvieu Caverns owns 33 underground storage caverns with an aggregate underground storage capacity of approximately 100 MMBbls, and a brine system with approximately 20 MMBbls of above-ground storage pit capacity and two brine production wells. These assets store and deliver NGLs (such as ethane and propane) and certain petrochemical products for industrial customers located along the upper Texas Gulf Coast.

     The following table summarizes the significant natural gas processing and NGL fractionation assets of our NGL Pipelines & Services business segment at February 5, 2007.

						Net Gas				Total Gas				Net				Total
				Our		Processing				Processing				Plant				Plant
				Ownership		Capacity				Capacity				Capacity				Capacity
Description of Asset		Location(s)		Interest		(Bcf/d) (1)				(Bcf/d)				(MBPD) (1)				(MBPD)
Natural gas processing facilities:
Toca		Louisiana		61.4%			0.66				1.10
Chaco		New Mexico		100%			0.65				0.65
Pioneer (2)		Wyoming		100%			0.60				0.60
Yscloskey		Louisiana		31.1%			0.58				1.85
North Terrebonne		Louisiana		43.5%			0.57				1.30
Calumet		Louisiana		31.2%			0.50				1.60
Neptune		Louisiana		66%			0.43				0.65
Pascagoula		Mississippi		40%			0.40				1.50
Thompsonville		Texas		100%			0.30				0.30
Shoup		Texas		100%			0.29				0.29
Gilmore		Texas		100%			0.26				0.26
Armstrong		Texas		100%			0.25				0.25
Matagorda		Texas		100%			0.25				0.25
Others (10 facilities) (3)		Texas, New Mexico, Louisiana		Various (4)			1.16				4.32
Total processing capacities							6.90				14.92
NGL fractionation facilities:
Mont Belvieu		Texas		75%											178				230
Shoup and Armstrong		Texas		100%											87				87
Norco		Louisiana		100%											75				75
Promix		Louisiana		50%											73				145
BRF		Louisiana		32.2%											19				60
Tebone		Louisiana		43.5%											12				30
Total plant capacities															444				627

     At the core of our natural gas processing business are 23 processing plants located in Texas, Louisiana, Mississippi, New Mexico and Wyoming. 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 from gathering pipelines. We operate the Toca, Chaco, North Terrebonne, Calumet, Neptune, Carlsbad and Pioneer plants and all of the Texas facilities. In addition to the natural gas processing plants noted above, we have begun construction on the Meeker facility and a new natural gas processing facility adjacent to our existing Pioneer plant. The Meeker facility will be constructed in the Piceance Basin of western Colorado and will have the capacity to process 1.7 Bcf/d of natural gas. Our new Pioneer natural gas processing plant located in Opal, Wyoming will have a natural gas processing capacity of 0.75 Bcf/d. On a weighted-average basis, utilization rates for these assets were 56%, 53% and 61% during the years ended December 31, 2006, 2005 and 2004, respectively. These rates reflect the periods in which we owned an interest in such facilities.

     Our NGL marketing activities utilize a fleet of approximately 830 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 and parts of Canada. We have rail loading and unloading facilities in Alabama, Arizona, California, Kansas, Louisiana, Minnesota, Mississippi, Nevada, North Carolina 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.

	§		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 located in southern Louisiana and along the Mississippi and Alabama Gulf Coast, including our Yscloskey, Pascagoula and Toca facilities.
	§		The Promix NGL fractionation facility receives mixed NGLs via pipeline from natural gas processing plants located in southern Louisiana and along the Mississippi Gulf Coast, including our Calumet, Neptune, Burns Point and Pascagoula facilities. In addition to the 362-mile Promix NGL Gathering System, Promix owns five NGL storage caverns and a barge loading facility that is integral to its operations.
	§		Our Shoup and Armstrong NGL fractionation facilities fractionate mixed NGLs supplied by our south Texas natural gas processing plants. The Shoup and Armstrong facilities supply NGLs transported by the DEP South Texas NGL Pipeline System.
	§		The BRF facility processes mixed NGLs from natural gas processing plants located in Alabama, Mississippi and southern Louisiana.

     On a weighted-average basis, utilization rates for our NGL fractionators were 75%, 74% and 70% during the years ended December 31, 2006, 2005 and 2004, respectively. These rates reflect the periods in which we owned an interest in such facilities. We own direct consolidated interests in all of our NGL fractionation facilities with the exception of a 50% interest in a facility owned by Promix and a 32.2% interest in a facility owned by Baton Rouge Fractionators LLC (“BRF”).

     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 currently loads cargoes of refrigerated propane and butane onto tanker vessels at rates of up to 5,000 barrels per hour. We are in the process of expanding our import and export facility. 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 127 MBPD, 119 MBPD and 91 MBPD for 2006, 2005 and 2004, respectively.

Onshore Natural Gas Pipelines & Services

     Our Onshore Natural Gas Pipelines & Services business segment includes approximately 18,889 miles of onshore natural gas pipeline systems that provide for the gathering and transmission of natural gas in Alabama, Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming. 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, Permian, Piceance and Greater Green River 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 or municipal customers or to other onshore pipelines.

     Certain of our onshore natural gas pipelines generate 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 Texas, 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, Permian Basin and Jonah 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. On a combined basis, these facilities (our Petal Gas Storage (“Petal”) and Hattiesburg Gas Storage (“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. High injection and withdrawal rates also allow customers to take advantage of periods of volatile natural gas prices and respond in situations where they have natural gas imbalance issues on pipelines connected to the storage facilities. Our salt dome storage facilities permit sustained periods of high natural gas deliveries, including 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) monthly demand payments, which are associated with storage capacity reservation and paid regardless of the customer’s usage, and (ii) storage fees per unit of volume stored at our facilities.

     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.

     Properties. The following table summarizes the significant assets of our Onshore Natural Gas Pipelines & Services business segment at February 5, 2007.

										Approximate
				Our						Capacity,				Gross
				Ownership		Length				Natural Gas				Capacity
Description of Asset		Location(s)		Interest		(Miles)				(MMcf/d)				(Bcf)
Onshore natural gas pipelines:
Texas Intrastate System		Texas		100%			8,140				5,155
Jonah Gathering System		Wyoming		14.4% (1)			643				1,750
Piceance Creek Gathering System		Colorado		100%			48				1,600
San Juan Gathering System		New Mexico, Colorado		100%			6,065				1,200
Acadian Gas System		Louisiana		Various (2)			1,042				954
Permian Basin System		Texas, New Mexico		100%			1,387				490
Alabama Intrastate System		Alabama		100%			408				200
Encinal Gathering System		Texas		100%			452				143
Other (5 systems) (3)		Texas, Mississippi		Various (4)			704
Total miles							18,889
Natural gas storage facilities:
Petal		Mississippi		100%											11.9
Hattiesburg		Mississippi		100%											4.0
Wilson		Texas		Leased (5)											6.4
Acadian		Louisiana		Leased (6)											3.0
Total gross capacity															25.3

     On a weighted-average basis, aggregate utilization rates for our onshore natural gas pipelines were approximately 71%, 73% and 75% during the years ended December 31, 2006, 2005 and 2004, respectively. These rates reflect the periods in which we owned an interest in such assets.

     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 and municipal 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, the Houston area, and the Houston Ship Channel industrial market. The Texas Intrastate System is comprised of the 7,292-mile Enterprise Texas Intrastate pipeline system, the 197-mile TPC Offshore gathering system and the 651-mile Channel pipeline system. The leased Wilson natural gas storage facility is an integral part of the Texas Intrastate System. We own 100% of the Texas Intrastate System with the exception of the Channel pipeline system, in which we own a 50% undivided interest.
	§		The Jonah Gathering System is located in the Greater Green River Basin of southwestern Wyoming. This system gathers natural gas from the Jonah and Pinedale fields for delivery to regional natural gas processing plants, including our Pioneer facility, and major interstate pipelines. In August 2006, we entered into a joint venture with TEPPCO and are proceeding with

			an expansion of the Jonah Gathering System. For additional information regarding this joint venture arrangement with TEPPCO and related expansion project, see Item 13 of this annual report.
	§		The Piceance Creek Gathering System consists of a recently constructed natural gas gathering pipeline located in the Piceance Basin of northwestern Colorado. This pipeline is owned by Piceance Creek Pipeline, LLC, the ownership interests of which we acquired from EnCana Oil & Gas (“EnCana”) in December 2006. The Piceance Creek Gathering System extends from a connection with EnCana’s Great Divide Gathering System located near Parachute, Colorado, northward through the heart of the Piceance Basin to our 1.7 Bcf/d Meeker natural gas treating and processing complex, which is currently under construction. Connectivity to EnCana’s Great Divide Gathering System will provide the Piceance Creek Gathering System with access to natural gas production from the southern portion of the Piceance basin, including production from EnCana’s Mamm Creek field. The Piceance Creek Gathering System was placed in service in January 2007 and began transporting initial volumes of approximately 300 MMcf/d of natural gas.
	§		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 10,400 wells in the San Juan Basin and delivers the natural gas to natural gas processing facilities, including our Chaco facility.
	§		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, 438-mile Acadian pipeline and the 27-mile Evangeline pipeline. The leased Acadian natural gas storage facility is an integral part of the Acadian Gas System.
			We contributed a direct 66% equity interest in Acadian Gas, which is a subsidiary that owns the Cypress and Acadian pipelines, to Duncan Energy Partners on February 5, 2007. We own the remaining 34% direct interest in Acadian Gas. For additional information regarding this subsequent event, see “Recent Developments” within this Item 1. Acadian Gas owns a 49.5% indirect interest in the Evangeline pipeline.
	§		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 452-mile Waha system and 935-mile Carlsbad system.
	§		The Alabama Intrastate System mainly 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.
	§		The Encinal Gathering System gathers natural gas from the Olmos and Wilcox formations and delivers into our Texas Intrastate System, which delivers the natural gas into our south Texas facilities for processing. We acquired this gathering system in connection with the Encinal acquisition in July 2006.
	§		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

     Our Offshore Pipelines & Services business segment includes (i) approximately 1,586 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 863 miles of offshore Gulf of Mexico crude oil pipeline systems and (iii) six multi-purpose offshore hub platforms located in the Gulf of Mexico with crude oil or natural gas processing capabilities.

     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 that are 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 transportation 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 (i) production from reserves committed under long-term contracts for the productive life of the relevant field or (ii) 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 six multi-purpose offshore hub platforms located in the Gulf of Mexico with crude oil or natural gas processing capabilities. 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 payments and commodity charges. Demand fees represent charges 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 payments and commodity charges, but demand payments generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers.

     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.

     Properties. The following table summarizes the significant assets of our Offshore Pipelines & Services business segment at February 5, 2007, 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:
VESCO Gathering System		13.1%			260								800
Manta Ray Offshore Gathering System		25.7%			250								206
High Island Offshore System		100%			204								1,800
Viosca Knoll Gathering System		100%			164								1,000
Green Canyon Laterals		Various (1)			136								649
Anaconda Gathering System (2)		100%			136								550
Independence Trail (3)		100%			134								1,000
Nautilus System		25.7%			101								154
East Breaks System		100%			85								400
Phoenix Gathering System		100%			78								450
Nemo Gathering System		33.9%			24								102
Falcon Natural Gas Pipeline		100%			14								400
Total miles					1,586
Offshore crude oil pipelines:
Cameron Highway Oil Pipeline		50%			373												250
Poseidon Oil Pipeline System		36%			322												144
Constitution Oil Pipeline		100%			67												80
Allegheny Oil Pipeline		100%			43												140
Marco Polo Oil Pipeline		100%			37												120
Typhoon Oil Pipeline		100%			17												80
Tarantula Oil Pipeline		100%			4												30
Total miles					863
Offshore platforms:
Independence Hub(3)		80%							8,000				1,000			NA
Marco Polo		50%							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

     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. On a weighted-average basis, aggregate utilization rates for our offshore natural gas pipelines were approximately 26%, 30% and 32% during the years ended December 31, 2006, 2005 and 2004, respectively. These rates reflect the periods in which we owned an interest in such assets.

     The following information highlights the general use of each of our principal Gulf of Mexico offshore natural gas pipelines.

	§		The VESCO Gathering System is a 260-mile regulated natural gas pipeline system associated with the Venice natural gas processing plant in Louisiana. This pipeline is an integral part of the natural gas processing operations of VESCO. Our 13.1% interest in this system is held through our equity method investment in VESCO.
	§		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. Our ownership interest in this pipeline is held indirectly through our equity method investment in Neptune Pipeline Company, L.L.C.
	§		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 HIOS pipeline system includes 10 pipeline junction and service platforms.
	§		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 the third-party owned Constitution platform to the ANR pipeline system. The Anaconda Gathering System includes our wholly-owned Typhoon, Marco Polo and Constitution natural gas pipelines. The Constitution natural gas pipeline 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 natural gas pipeline during the first quarter of 2006.
	§		The Independence Trail natural gas pipeline will transport natural gas from our Independence Hub platform to the Tennessee Gas Pipeline. Natural gas transported on the Independence Trail will come from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. This pipeline includes one pipeline junction platform at West Delta 68. We completed construction of the Independence Trail natural gas pipeline during 2006, with an expected in-service date during the second half of 2007.
	§		The Nautilus System connects our Manta Ray Offshore Gathering System to our Neptune natural gas processing plant on the Louisiana gulf coast. Our ownership interest in this pipeline is held indirectly through our equity method investment in Neptune Pipeline Company, L.L.C.
	§		The East Breaks System connects the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25 to the HIOS pipeline system.
	§		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. Our ownership interest in this pipeline is held indirectly through our equity method investment in Nemo Gathering Company, LLC.

§

The Falcon Natural 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. On a weighted-average basis, aggregate utilization rates for our offshore crude oil pipelines were approximately 18%, 17% and 27% during the years ended December 31, 2006, 2005 and 2004, respectively. These rates reflect the periods in which we owned an interest in such assets.

	§		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. This pipeline includes one pipeline junction platform. Our 50% joint control ownership interest in this pipeline is held indirectly through our equity method investment in Cameron Highway Oil Pipeline Company (“Cameron Highway”).
	§		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. This system includes one pipeline junction platform. Our ownership interest in this pipeline is held indirectly through our equity method investment in Poseidon Oil Pipeline Company, LLC.
	§		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 transports 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. Anadarko will operate the Independence Hub platform once it becomes operational.

     On a weighted-average basis, utilization rates with respect to natural gas processing capacity of our offshore platforms were approximately 17%, 27% and 33% during the years ended December 31, 2006, 2005 and 2004, respectively. Likewise, utilization rates for our offshore platforms were approximately 19%, 9% and 14%, respectively, in connection with platform crude oil processing capacity. These rates reflect the periods in which we owned an interest in such assets. In addition to the offshore platforms we identified in the preceding table, we own or have an ownership interest in fifteen pipeline junction and service platforms. Our pipeline junction and service platforms do not have any processing capacity.

	§		The Independence Hub platform is located in Mississippi Canyon Block 920. This platform will process crude oil and natural gas gathered from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. We expect to complete construction of the Independence Hub platform in March 2007, with an expected in-service date during the second half of 2007.
	§		The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural gas from the Marco Polo, K2, and K2 North fields and should begin processing production from the Genghis Khan field in the second quarter of 2007. These fields are located in the South

			Green Canyon area of the Gulf of Mexico. Our 50% joint control ownership interest in this platform is held indirectly through our equity method investment in Deepwater Gateway LLC.
	§		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

     Our Petrochemical Services business segment includes four propylene fractionation facilities, an isomerization complex, and an octane additive production facility. This segment also includes approximately 679 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 609 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, we sell our petrochemical products at market-related prices, which may 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. Isobutane is used in the production of alkylate for motor gasoline, propylene oxide, isooctane and methyl tertiary butyl ether (“MTBE”). 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 isooctane, which is an additive used in reformulated motor gasoline blends to increase octane, and isobutylene. The facility produces isooctane and isobutylene using feedstocks of high-purity isobutane, which is supplied using production from our isomerization units.

     Prior to mid-2005, the facility produced MTBE. 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 eliminated the requirement of oxygenates in reformulated motor gasoline. As a result of such developments, we modified the facility to produce isooctane and isobutylene. Depending on the outcome of various factors, the facility may be further modified in the future to produce alkylate, another motor gasoline additive.

     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 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 and petrochemical companies 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

     Properties. The following table summarizes the significant assets of our Petrochemical Services segment at February 5, 2007, all of which we operate.

Net

Total

Our

Plant

Plant

Ownership

Capacity

Capacity

Length

Description of Asset

Location(s)

Interest

(MBPD)

(MBPD)

(Miles)

Propylene fractionation facilities:

Mont Belvieu (3 plants)

Texas

Various (1)

58

72

BRPC

Louisiana

30% (2)

7

23

Total capacity

65

95

Isomerization facility:

Mont Belvieu (3)

Texas

100%

116

116

Petrochemical pipelines:

Lou-Tex and Sabine Propylene

Texas, Louisiana

100%(4)

284

Texas City RGP Gathering System

Texas

100%

108

Lake Charles

Texas, Louisiana

50%

83

Others (6 systems)(5)

Texas, Louisiana

Various (6)

204

Total miles

679

Octane additive production facilities:

Mont Belvieu

Texas

100%

12

12

     We produce polymer grade propylene at our Mont Belvieu location 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. On a weighted-average basis, aggregate utilization rates of our propylene fractionation facilities were approximately 86%, 83% and 86% during the years ended December 31, 2006, 2005 and 2004, respectively. 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.

     The Lou-Tex propylene pipeline is used to transport chemical grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas. The Sabine pipeline is used to transport polymer grade propylene from Port Arthur, Texas to a pipeline interconnect in Cameron Parish, Louisiana. We own these pipelines through our subsidiaries, Lou-Tex Propylene and Sabine Propylene.

     On February 5, 2007, we contributed a direct 66% equity interest in our subsidiaries that own the Lou-Tex Propylene and Sabine Propylene pipelines to Duncan Energy Partners. We own the remaining 34% direct interest in these subsidiaries. For additional information regarding this subsequent event, see “Recent Developments” within this Item 1.

     The maximum number of barrels that our petrochemical pipelines can transport per day depends upon the operating balance achieved at a given point in time between various segments of the systems. Since the operating balance is dependent upon the mix of products to be shipped and demand levels at various delivery points, the exact capacities of our petrochemical pipelines cannot be determined. We measure the utilization rates of such pipelines in terms of net throughput (i.e., on a net basis in accordance

with our ownership interest). Total net throughput volumes for these pipelines were 97 MBPD, 64 MBPD and 71 MBPD during the years ended December 31, 2006, 2005 and 2004, respectively.

     Our octane additive facility currently has an isooctane production capacity of 12.0 MBPD. The facility was capable of producing only MTBE prior to mid-2005 at a rate up to 15.5 MBPD. On a weighted-average combined product basis, utilization rates for this facility were approximately 45%, 29% and 83% during the years ended December 31, 2006, 2005 and 2004, respectively.

Title to Properties

     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.

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 with industry partners. We believe that we are positioned to continue to grow our system of assets through the construction of new facilities and to capitalize on expected future production increases from such areas as the Piceance Basin of western Colorado, the Greater Green River Basin in Wyoming, Barnett Shale in North Texas, and the deepwater Gulf of Mexico. For a discussion of our capital spending program, see “Capital Spending” included under Item 7 of this annual report.

Regulation

Interstate Regulation

     Liquids Pipelines. Certain of our crude oil and NGL pipeline systems (collectively referred to as “liquids pipelines”) are interstate common carrier pipelines subject to regulation by the FERC under the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992 (“Energy Policy Act”). The ICA prescribes that interstate tariffs must be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. FERC regulations require that interstate oil pipeline transportation rates be filed with the FERC and posted publicly.

     The ICA permits interested persons to challenge proposed new or changed rates and authorizes the FERC to investigate such rates and to suspend their effectiveness for a period of up to seven months. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it may require the carrier to refund the revenues in excess of the prior tariff during the term of the investigation. The FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to two years prior to the filing of its complaint.

     The Energy Policy Act deemed liquids pipeline rates that were in effect for the twelve months preceding enactment and that had not been subject to complaint, protest or investigation, just and reasonable under the Energy Policy Act (i.e., “grandfathered”). Some, but not all, our interstate liquids pipeline rates are considered grandfathered under the Energy Policy Act. Certain other rates for our

interstate liquids pipeline services are charged pursuant to a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the change from year-to-year in the Producer Price Index for finished goods (“PPI”). A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline’s costs. Effective March 21, 2006, FERC concluded that for the five-year period commencing July 1, 2006, liquids pipelines charging indexed rates may adjust their indexed ceilings annually by the PPI plus 1.3%.

     As an alternative to using the indexing methodology, interstate liquids pipelines may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements with all of the pipeline’s shippers that the rate is acceptable.

     Because of the complexity of ratemaking, the lawfulness of any rate is never assured. The FERC uses prescribed rate methodologies for approving regulated tariff rates for transporting crude oil and refined products. These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting higher costs. Changes in the FERC’s approved methodology for approving rates could adversely affect us. Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow. Challenges to our tariff rates could be filed with the FERC. We believe the transportation rates currently charged by our interstate common carrier liquids pipelines are in accordance with the ICA. However, we cannot predict the rates we will be allowed to charge in the future for transportation services by such pipelines.

     The Lou-Tex Propylene pipeline is an interstate common carrier pipeline regulated under the ICA by the Surface Transportation Board (“STB”), a part of the United States Department of Transportation. If the STB finds that a carrier’s rates are not just and reasonable or are unduly discriminatory or preferential, it may prescribe a reasonable rate. In determining a reasonable rate, the STB will consider, among other factors, the effect of the rate on the volumes transported by that carrier, the carrier’s revenue needs and the availability of other economic transportation alternatives.

     The STB does not need to provide rate relief unless shippers lack effective competitive alternatives. If the STB determines that effective competitive alternatives are not available and a pipeline holds market power, then we may be required to show that our rates are reasonable.

     Natural Gas Pipelines. Our interstate natural gas pipelines and storage facilities are regulated by the FERC under the Natural Gas Act of 1938 (“NGA”). Under the NGA, the rates for service on these interstate facilities must be just and reasonable and not unduly discriminatory. We operate these interstate facilities pursuant to tariffs which set forth terms and conditions of service. These tariffs must be filed with and approved by the FERC pursuant to its regulations and orders. Our tariff rates may be lowered by the FERC, on its own initiative, or as a result of challenges to the rates by third parties if they are found unlawful and the FERC could require refunds of amounts collected under such unlawful rates. Our rates are derived based on a cost-of-service methodology.

     One element of the FERC’s cost-of-service methodology as it affects partnerships such as ours is an income tax allowance. Pursuant to an order on remand of a decision by the U.S. Court of Appeals for the District of Columbia Circuit in BP West Coast, LLC v. FERC and a policy statement regarding income tax allowance issued by the FERC, the FERC will permit a pipeline to include in cost-of-service a tax allowance to reflect actual or potential tax liability on its public utility income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case by case basis. Both the FERC’s income tax allowance policy and its initial application in an individual pipeline proceeding are being challenged in the court of appeals.

     The FERC’s authority over companies that provide natural gas pipeline transportation or storage services also includes (i) certification, construction, and operation of new facilities; (ii) the acquisition, extension, disposition or abandonment of such facilities; (iii) the maintenance of accounts and records; (iv) the initiation, extension and discontinuation of covered services; and (v) various other matters. In addition,

pursuant to the Energy Policy Act of 2005, the NGA and the Natural Gas Policy Act of 1978 (“NGPA”) were amended to increase civil and criminal penalties for any violation of the NGA, NGPA and any rules, regulations or orders of the FERC up to $1 million per day per violation.

     Offshore Pipelines. Our offshore pipeline systems are subject to federal regulation under the Outer Continental Shelf Lands Act (“OCSLA”), which requires that all pipelines operating on or across the outer continental shelf provide nondiscriminatory transportation service.

Intrastate Regulation

     Our intrastate NGL and natural gas pipelines are subject to regulation in many states, including Alabama, Colorado, Louisiana, Mississippi, New Mexico and Texas. Certain of our intrastate pipelines are subject to regulation by the FERC under the NGPA and provide transportation and storage service pursuant to Section 311 of the NGPA and the FERC’s regulations. Under Section 311 of the NGPA, an intrastate pipeline company may transport gas for an interstate pipeline or any local distribution company served by an interstate pipeline. We are required to provide these services on an open and nondiscriminatory basis. The rates for 311 service may be established by the FERC or the respective state agency, but may not exceed a fair and equitable rate.

     Certain other of our pipeline systems operate within a single state and provide intrastate pipeline transportation services. These pipeline systems are subject to various regulations and statutes mandated by state regulatory authorities. Although the applicable state statutes and regulations vary, they generally require that intrastate pipelines publish tariffs setting forth all rates, rules and regulations applying to intrastate service, and generally require that pipeline rates and practices be reasonable and nondiscriminatory. Shippers may also challenge our intrastate tariff rates and practices on our pipelines.

Environmental and Safety Matters

General

     Our operations are subject to multiple environmental obligations and potential liabilities under a variety of federal, state and local laws and regulations. These include, without limitation: the Comprehensive Environmental Response, Compensation, and Liability Act; the Resource Conservation and Recovery Act; the Clean Air Act; the Federal Water Pollution Control Act or the Clean Water Act; the Oil Pollution Act; and analogous state and local laws and regulations. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals, with respect to air emissions, water quality, wastewater discharges, and solid and hazardous waste management. Failure to comply with these requirements may expose us to fines, penalties and/or interruptions in our operations that could influence our results of operations. If an accidental leak, spill or release of hazardous substances occurs at a facility that we own, operate or otherwise use, or where we send materials for treatment or disposal, we could be held jointly and severally liable for all resulting liabilities, including investigation, remedial and clean-up costs. Likewise, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination. Any or all of this could materially affect our results of operations and cash flows.

     We believe our operations are in material compliance with applicable environmental and safety laws and regulations, other than certain matters discussed under Item 3 of this annual report, and that compliance with existing environmental and safety laws and regulations are not expected to have a material adverse effect on our financial position, results of operations or cash flows. Environmental and safety laws and regulations are subject to change. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating

restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows.

Water

     The Federal Water Pollution Control Act of 1972, as renamed and amended as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters of the United States, as well as state waters. Permits must be obtained to discharge pollutants into these waters. The Clean Water Act imposes substantial potential liability for the removal and remediation of pollutants.

     The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution — prevention, containment and cleanup, and liability. OPA subjects owners of certain facilities to strict, joint and potentially unlimited liability for containment and removal costs, natural resource damages and certain other consequences of an oil spill, where such spill is into navigable waters, along shorelines or in the exclusive economic zone of the U.S. Any unpermitted release of petroleum or other pollutants from our operations could also result in fines or penalties. OPA applies to vessels, offshore platforms and onshore facilities, including terminals, pipelines and transfer facilities. In order to handle, store or transport oil, shore facilities are required to file oil spill response plans with the United States Coast Guard, the United States Department of Transportation Office of Pipeline Safety (“OPS”) or the EPA, as appropriate.

     Some states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Contamination resulting from spills or releases of petroleum products is an inherent risk within our industry. To the extent that groundwater contamination requiring remediation exists along our pipeline systems as a result of past operation, we believe any such contamination could be controlled or remedied without having a material adverse effect on our financial position, but such costs are site specific and we cannot predict that the effect will not be material in the aggregate.

Air Emissions

     Our operations are subject to the Federal Clean Air Act (the “Clean Air Act”) and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions.

     Our permits and related compliance obligations under the Clean Air Act, as well as recent or soon to be adopted changes to state implementation plans for controlling air emissions in regional, non-attainment areas, may require our operations to incur capital expenditures to add to or modify existing air emission control equipment and strategies. In addition, some of our facilities are included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the Clean Air Act and many state laws. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that such requirements will not have a material adverse effect on our operations, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

     Congress is currently considering proposed legislation directed at reducing “greenhouse gas emissions.” It is not possible at this time to predict how legislation that may be enacted to address greenhouse gas emissions would impact our business. However, future laws and regulations could result in

increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial position, results of operations and cash flows.

Solid Waste

     In our normal operations, we generate hazardous and non-hazardous solid wastes, including hazardous substances, that are subject to the requirements of the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws, which impose detailed requirements for the handling, storage treatment and disposal of hazardous and solid waste. We also utilize waste minimization and recycling processes to reduce the volumes of our waste. Amendments to RCRA required the EPA to promulgate regulations banning the land disposal of all hazardous wastes unless the waste meets certain treatment standards or the land-disposal method meets certain waste containment criteria.

Environmental Remediation

     The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, on certain classes of persons who contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred, transporters that select the site of disposal of hazardous substances and companies that disposed of or arranged for the disposal of any hazardous substances found at a facility. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our operations, our pipeline systems generate wastes that may fall within CERCLA’s definition of a “hazardous substance.” In the event a disposal facility previously used by us requires clean up in the future, we may be responsible under CERCLA for all or part of the costs required to clean up sites at which such wastes have been disposed.

Pipeline Safety Matters

     We are subject to regulation by the United States Department of Transportation (“DOT”) under the Accountable Pipeline and Safety Partnership Act of 1996, sometimes referred to as the Hazardous Liquid Pipeline Safety Act (“HLPSA”), and comparable state statutes relating to the design, installation, testing, construction, operation, replacement and management of our pipeline facilities. The HLPSA covers petroleum and petroleum products. The HLPSA requires any entity that owns or operates pipeline facilities to (i) comply with such regulations, (ii) permit access to and copying of records, (iii) file certain reports and (iv) provide information as required by the Secretary of Transportation. We believe that we are in material compliance with these HLPSA regulations.

     We are subject to the DOT regulation requiring qualification of pipeline personnel. The regulation requires pipeline operators to develop and maintain a written qualification program for individuals performing covered tasks on pipeline facilities. The intent of this regulation is to ensure a qualified work force and to reduce the probability and consequence of incidents caused by human error. The regulation establishes qualification requirements for individuals performing covered tasks. We believe that we are in material compliance with these DOT regulations.

     We are also subject to the DOT Integrity Management regulations, which specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas (“HCAs”). HCAs are defined to include populated areas, unusually sensitive environmental areas and commercially navigable waterways. The regulation requires the development and implementation of an Integrity Management Program (“IMP”) that utilizes internal pipeline inspection, pressure testing, or other equally effective means to assess the integrity of HCA pipeline segments. The regulation also requires periodic review of HCA

pipeline segments to ensure adequate preventative and mitigative measures exist and that companies take prompt action to address integrity issues raised by the assessment and analysis. In compliance with these DOT regulations, we identified our HCA pipeline segments and have developed an IMP. We believe that the established IMP meets the requirements of these DOT regulations.

Risk Management Plans

     We are subject to the EPA’s Risk Management Plan (“RMP”) regulations at certain facilities. These regulations are intended to work with the Occupational Safety and Health Act (“OSHA”) Process Safety Management regulations (see “Safety Matters” below) to minimize the offsite consequences of catastrophic releases. The regulations required us to develop and implement a risk management program that includes a five-year accident history, an offsite consequence analysis process, a prevention program and an emergency response program. We believe we are operating in material compliance with our risk management program.

Safety Matters

     Certain of our facilities are also subject to the requirements of the federal OSHA and comparable state statutes. We believe we are in material compliance with OSHA and state requirements, including general industry standards, record keeping requirements and monitoring of occupational exposures.

     We are subject to OSHA Process Safety Management (“PSM”) regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves certain flammable liquid or gas. We believe we are in material compliance with the OSHA PSM regulations.

     The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and disclose information about the hazardous materials used in our operations. Certain parts of this information must be reported to employees, state and local governmental authorities and local citizens upon request.

Employees

     As of December 31, 2006, approximately 1,900 persons spend 100% of their time engaged in the management and operations of our business, and 100% of the cost for their services is reimbursed to EPCO under an administrative services agreement, except for approximately 80 persons employed and paid directly by Dixie. In addition approximately 1,100 persons assigned to EPCO’s shared service organizations spend all or a portion of their time engaged in our business. The cost for their services is reimbursed to EPCO under an administrative services agreement (see Item 13) and is generally based on the percentage of time such employees perform services on our behalf during the year. All of the foregoing persons, except the approximately 80 who are employed directly by Dixie, are employees of EPCO. In addition to the EPCO employees, there are approximately 150 contract maintenance and other various contract personnel engaged in our business. For additional information regarding our relationship with EPCO, see Item 13 of this annual report.

Available Information

     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 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) 381-6521 for paper copies of these reports free of charge.

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.

     The following section lists some, but not all, of the key risk factors that may have a direct impact on our business, results of operations, cash flows and financial condition. The items are not listed in terms of importance or level of risk.

Risks Relating to Our Business

Changes in demand for and production of hydrocarbon products may materially adversely affect our results of operations, cash flows and financial condition.

     We operate predominantly in the midstream energy sector which includes 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. Changes in prices and changes in the relative price levels may impact demand for hydrocarbon products, which in turn may impact production and volumes of product for which we provide services. We may also incur price risk to the extent counterparties do not perform in connection with our marketing of natural gas, NGLs and propylene.

     In the past, the prices of natural gas have been extremely volatile, and we expect this volatility to continue. The NYMEX daily settlement price for natural gas for the prompt month contract in 2004 ranged from a high of $8.75 per MMBtu to a low of $4.57 per MMBtu. In 2005, the same index ranged from a high of $15.38 per MMBtu to a low of $5.79 per MMBtu. In 2006, the same index ranged from a high of $10.63 per MMBtu to a low of $4.20 per MMBtu.

     Generally, the prices of natural gas, NGLs, 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. Some of 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;

	§		the impact of conservation efforts;
	§		the extent of governmental regulation and taxation 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. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. If natural gas prices increase significantly in relation to NGL product prices or if the demand for ethylene falls (and, therefore, the demand for ethane by NGL producers falls), it may be more profitable for natural gas producers to leave the ethane in the natural gas stream to be burned as fuel than to extract the ethane from the mixed NGL stream for sale as an ethylene feedstock.

     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. Propylene is sold to petrochemical companies for a variety of uses, principally for the production of polypropylene. Propylene is subject to rapid and material price fluctuations. Any downturn in the domestic or international economy could cause reduced demand for, and an oversupply of propylene, which could cause a reduction in the volumes of propylene that we transport.

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 but not limited to:

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

Our future debt level may limit our flexibility to obtain additional financing and pursue other business opportunities.

     As of December 31, 2006, we had approximately $5.3 billion of consolidated debt outstanding. In addition, as of February 5, 2007, Duncan Energy Partners had approximately $200.0 million outstanding under its credit facility. The amount of our future debt could have significant effects on our operations, including, among other things:

	§		a substantial portion of our cash flow, including that of Duncan Energy Partners, 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 and future credit and 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, including possible acquisition opportunities;
	§		our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

	§		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, see 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, see 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 (either for ourselves or direct Duncan Energy Partners to do so) 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 but not limited to:

	§		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.

Acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per unit basis.

     Even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless reduce our cash from operations on a per unit basis. Any acquisition involves potential risks, including, among other things:

	§		mistaken assumptions about volumes, revenues and costs, including synergies;
	§		an inability to integrate successfully the businesses we acquire;
	§		decrease in our liquidity as a result of our using a significant portion of our available cash or borrowing capacity to finance the acquisition;

	§		a significant increase in our interest expense or financial leverage if we incur additional debt to finance the acquisition;
	§		the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;
	§		an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;
	§		limitations on rights to indemnity from the seller;
	§		mistaken assumptions about the overall costs of equity or debt;
	§		the diversion of management’s and employees’ attention from other business concerns;
	§		unforeseen difficulties operating in new product areas or new geographic areas; and
	§		customer or key employee losses at the acquired businesses.

     If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

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 have significant expenditures for the development and construction of energy infrastructure assets, including construction and development projects with significant logistical, technological and staffing challenges. We may not be able to complete our projects at the costs we estimated at the time of each project’s initiation or that we currently estimate. For example, material and labor cost trends associated with our projects in the Rocky Mountains region have increased since the initiation of these projects due to factors such as higher transportation costs and the availability of construction personnel. Similarly, force majeure events such as hurricanes along the Gulf Coast may cause delays, shortages of skilled labor and additional expenses for these construction and development projects, as were experienced with Hurricanes Katrina and Rita during 2005.

Our construction of new assets is subject to regulatory, environmental, political, legal and economic risks, which may result in delays, increased costs or decreased cash flows.

     One of the ways we intend to grow our business is through the construction of new midstream energy assets. The construction of new assets involves numerous operational, regulatory, environmental, political and legal risks beyond our control and may require the expenditure of significant amounts of capital. These potential risks include, among other things, the following:

§

we may be unable to complete construction projects on schedule or at the budgeted cost due to the unavailability of required construction personnel or materials, accidents, weather conditions or an inability to obtain necessary permits;

	§		we will not receive any material increases in revenues until the project is completed, even though we may have expended considerable funds during the construction phase, which may be prolonged;
	§		we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize;
	§		since we are not engaged in the exploration for and development of natural gas reserves, we may not have access to third-party estimates of reserves in an area prior to our constructing facilities in the area. As a result, we may construct facilities in an area where the reserves are materially lower than we anticipate;
	§		where we do rely on third-party estimates of reserves in making a decision to construct facilities, these estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating reserves; and
	§		we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical.

     A materialization of any of these risks could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from expansion opportunities or construction projects.

     One of the connections between our DEP South Texas NGL Pipeline System and the Mont Belvieu facility is a pipeline we have leased from TEPPCO. The initial term of this lease will expire on September 15, 2007, and if we are unable to construct our planned replacement pipeline or extend the lease, the operations of our DEP South Texas NGL Pipeline System will be interrupted. We cannot assure you that any construction will not be delayed due to government permits, weather conditions or other factors beyond our control.

We may not be able to consummate future public offerings of Duncan Energy Partners on terms that we expect or at all, which would result in less cash available for us to fund our capital spending program.

     Duncan Energy Partners was formed in part to acquire, own and operate midstream energy businesses of ours. In the future, we may contribute additional equity interests in our subsidiaries to Duncan Energy Partners and use the proceeds we receive from Duncan Energy Partners to fund our capital spending program. Although Duncan Energy Partners successfully completed its initial public offering in February 2007, there is no guarantee that Duncan Energy Partners will be able to complete future offerings of its securities in amounts that we would expect. If this occurs, we would have less cash available to fund our capital spending program, which could result in less cash distributions.

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 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, Enterprise GP Holdings and TEPPCO to service such indebtedness. Any distributions by us, Enterprise GP Holdings and TEPPCO to such entities will be made only after satisfying our then current obligations to creditors. Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect the separateness of us and our general partner from the entities that control our general partner, our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of Dan L. Duncan or the entities that control our general partner were viewed as substantially lower or more risky than ours.

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 partnership holding company with no business operations and our operating subsidiaries conduct all of our operations and own all of our operating assets. Our only significant assets are the ownership 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. The ability of our subsidiaries and joint ventures to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC policies. For example, all cash flows from Evangeline are currently used to service its debt.

     In addition, the charter documents governing our joint ventures typically allow their respective joint venture management committees 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. The location of our assets and our customers’ assets in the U.S. Gulf Coast region makes them particularly vulnerable to hurricane risk.

     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 and will not cover amounts up to applicable deductibles. 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. For example, change in the insurance markets subsequent to the terrorist attacks on September 11, 2001 and the hurricanes in 2005 have made it more difficult for us to obtain certain types of coverage. As a result, EPCO may not be able to renew existing insurance policies on behalf of us or procure other desirable insurance on commercially reasonable terms, if at all. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position and results of operations. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient if such an event were to occur.

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

     At December 31, 2006, our balance sheet reflected $590.5 million of goodwill and $1.0 billion 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. Accounting principles generally accepted in the United States (“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, 2006, we had approximately $5.3 billion of consolidated debt, of which approximately $3.8 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. Certain environmental laws, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to cleanup and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released. Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for

personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

     We will make expenditures in connection with environmental matters as part of normal capital expenditure programs. However, future environmental law developments, such as stricter laws, regulations, permits or enforcement policies, could significantly increase some costs of our operations, including the handling, manufacture, use, emission or disposal of substances and wastes.

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 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 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, see 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.

We are subject to strict regulations at many of our facilities regarding employee safety, and failure to comply with these regulations could adversely affect our ability to make distributions to you.

     The workplaces associated with our facilities are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities and local residents. The failure to comply with OSHA requirements or general industry standards, keep adequate records or monitor occupational exposure to regulated substances could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.

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 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 key members of our senior management team could have a material adverse effect on our business, results of operations, cash flows, market price of our securities and financial condition.

EPCO’s employees may be subjected to conflicts in managing our business and the allocation of time and compensation costs between our business and the business of EPCO and its other affiliates.

     We have no officers or employees and rely solely on officers of our general partner and employees of EPCO. Certain of our officers are also officers of EPCO and other affiliates of EPCO. These relationships may create conflicts of interest regarding corporate opportunities and other matters, and the resolution of any such conflicts may not always be in our or our unitholders’ best interests. In addition, these overlapping officers allocate their time among us, EPCO and other affiliates of EPCO. These officers face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

     We have entered into an administrative services agreement that governs business opportunities among entities controlled by EPCO, which includes us and our general, Enterprise GP Holdings and its general partner, Duncan Energy Partners and its general partner and TEPPCO and its general partner. For information regarding how business opportunities are handled within the EPCO group of companies, please read Item 13 of this annual report.

     We do not have an independent compensation committee, and aspects of the compensation of our executive officers and other key employees, including base salary, are not reviewed or approved by our independent directors. The determination of executive officer and key employee compensation could involve conflicts of interest resulting in economically unfavorable arrangements for us.

Risks Relating to 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 common unit may decrease;
	§		the ratio of taxable income to distributions may increase;

	§		the relative voting strength of each previously outstanding common 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 the amount of cash we have available for distribution 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 EPCO and its affiliates, including our general partner 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 EPCO and its affiliates, including officers and directors of Enterprise Products GP, for all expenses they incur on our behalf, including allocated overhead. These amounts will include all costs incurred in managing and operating us, including costs for rendering administrative staff and support services to us, and overhead allocated to us by EPCO. The payment of these amounts could adversely affect our ability to pay cash distributions to holders of our

units. EPCO has sole discretion to determine the amount of these expenses. In addition, EPCO and its affiliates may provide other services to us for which we will be charged fees as determined by EPCO.

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 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, see Item 13 included within this annual report.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors. In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.

     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. The board of directors of our general partner, including the independent directors, is chosen by the owners of the general partner and not by the unitholders.

     Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have no practical ability to remove Enterprise Products GP or its officers or directors. 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 33.9% 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 common 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.

     The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. You could have unlimited liability for our obligations if a court or government agency determined that:

	§		we were conducting business in a state, but had not complied with that particular state’s partnership statute; or
	§		your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business.

Unitholders may have liability to repay distributions.

     Under certain circumstances, our unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

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 owned 26,976,249 of our common units, representing approximately 6.2% of our outstanding common units at December 31, 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. Shell sold 2,431,300 of our common units to third parties during the year ended December 31, 2006. In addition, Shell sold approximately 7,340,500 of our common units during January 2007.

     Affiliates of Lewis Energy Group L.P. (collectively, “Lewis”) owned 7,070,644 of our common units, representing approximately 1.6% of our outstanding common units at December 31, 2006, and have publicly announced their intention to reduce their holdings of our common units on an orderly schedule, taking into account market conditions. All of the common units held by Lewis are registered for resale under our effective registration statement on Form S-3. Lewis sold 45,200 of our common units to third parties during the year ended December 31, 2006.

     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 1, 2007, we had 432,408,430 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

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash 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%. 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. Thus, 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 a material amount of entity level taxation. In addition, because of widespread state budget deficits and other reasons, several states (including Texas) are evaluating ways to enhance state-tax collections. For example, our operating subsidiaries will be subject to a newly revised Texas franchise tax (the “Texas Margin Tax”) on the portion of their revenue that is generated in Texas beginning for tax reports due on or after January 1, 2008. Specifically, the Texas Margin Tax will be imposed at a maximum effective rate of 0.7% of the operating subsidiaries’ gross revenue that is apportioned to Texas. If any additional state were to impose a entity-level tax upon us or our operating subsidiaries, 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 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) 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. 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 be 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 3. Legal Proceedings.

     On occasion, we are named as a defendant in litigation relating to our normal business activities, including regulatory and environmental matters. Although we insure 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 activities. We are not aware of any significant litigation, pending or threatened, that we believe may individually have a significant adverse effect on our financial position, cash flows or results of operations.

     A number of lawsuits have been filed by municipalities and other water suppliers against various manufacturers of reformulated gasoline containing methyl tertiary butyl ether (“MTBE”). In general, such suits have not named manufacturers of MTBE as defendants, and there have been no such lawsuits filed against our subsidiary that owns an octane-additive production facility. It is possible, however, that former MTBE manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

     We acquired additional ownership interests in our octane-additive production facility from affiliates of Devon Energy Corporation (“Devon”), which sold us its 33.3% interest in 2003, and Sunoco, Inc. (“Sun”), which sold us its 33.3% interest in 2004. As a result of these acquisitions, we own 100% of our Mont Belvieu, Texas octane-additive production facility. Devon and Sun have indemnified us for any liabilities (including potential liabilities as described in the preceding paragraph) 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 our octane-additive production facility.

     On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of other unitholders of TEPPCO, and derivatively on behalf of TEPPCO, concerning, among other things, certain transactions involving TEPPCO and us or our affiliates. The complaint names as defendants (i) TEPPCO, its current and certain former directors, and certain of its affiliates; (ii) us and certain of our affiliates, including the parent company of our general partner; (iii) EPCO, Inc.; and (iv) Dan L. Duncan. The complaint alleges, among other things, that the defendants have caused TEPPCO to enter into certain transactions with us or our affiliates that are unfair to TEPPCO or otherwise unfairly favored us or our affiliates over TEPPCO. These transactions are alleged to include the joint venture to further expand the Jonah Gathering System entered into by TEPPCO and one of our affiliates in August 2006 and the sale by TEPPCO to one of our affiliates of the Pioneer gas processing plant in March 2006. The complaint seeks (i) rescission of these transactions or an award of rescissory damages with respect thereto; (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the complaint; and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. We believe this lawsuit is without merit and intend to vigorously defend against it. For information regarding our relationship with TEPPCO, see Item 13 of this annual report.

     On February 13, 2007, our Operating Partnership received notice from the U.S. Department of Justice (“DOJ”) that it was the subject of a criminal investigation related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”). Our Operating Partnership is the operator of this pipeline. On February 14, 2007, our Operating Partnership received a letter from the Environment and Natural Resources Division (“ENRD”) of the DOJ regarding this incident and a previous release of ammonia on September 27, 2004 from the same pipeline. The ENRD has indicated that it may pursue civil damages against our Operating Partnership and Magellan as a result of these incidents. Based on this correspondence from the ENRD, the statutory maximum amount of civil fines that could be assessed against our Operating Partnership and Magellan is up to $17.4 million in the aggregate. Our Operating Partnership is cooperating with the DOJ and is hopeful that an

expeditious resolution acceptable to all parties will be reached in the near future. Our Operating Partnership is seeking defense and indemnity under the pipeline operating agreement between it and Magellan. At this time, we do not believe that a final resolution of either the criminal investigation by the DOJ or the civil claims by the ENRD will have a material impact on our consolidated results of operations.

     On October 25, 2006, a rupture in the Magellan Ammonia Pipeline resulted in the release of ammonia near Clay Center, Kansas. We and Magellan are in the process of estimating the repair and remediation costs associated with this release. Environmental remediation efforts continue in and around the site of the release under the supervision and management of affiliates of Magellan. Our operating agreement with Magellan provides the Operating Partnership with an indemnity clause for claims arising from such releases. At this time, we do not believe that this incident will have a material impact on our consolidated results of operations.

     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 1, 2007, there were an approximately 930 unitholders of record of our common units. The following table presents 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
2005
1st Quarter		$	28.350			$	23.920			$	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
2006
1st Quarter		$	26.000			$	23.690			$	0.4450			Apr. 28, 2006				May 10, 2006
2nd Quarter		$	25.710			$	23.760			$	0.4525			Jul. 31, 2006				Aug. 10, 2006
3rd Quarter		$	27.060			$	25.000			$	0.4600			Oct. 31, 2006				Nov. 8, 2006
4th Quarter		$	29.980			$	26.050			$	0.4675			Jan. 31, 2007				Feb. 8, 2007

     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, see “Liquidity and Capital Resources” included under Item 7 of this annual report. Although the payment of cash distributions 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 2006.

Common Units Authorized for Issuance Under Equity Compensation Plan

     See 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 2006. 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, 2007, we and our affiliates could repurchase up to 618,400 additional common units under this repurchase program.

Item 6. Selected Financial Data.

     The following table presents selected historical consolidated financial data of our partnership. This information has been derived from our audited financial statements 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 are in thousands (except per unit data).

		For the Year Ended December 31,
		2006				2005				2004				2003				2002
Operating results data: (1)
Revenues		$	13,990,969			$	12,256,959			$	8,321,202			$	5,346,431			$	3,584,783
Income from continuing operations (2)		$	599,683			$	423,716			$	257,480			$	104,546			$	95,500
Income per unit from continuing operations:
Basic		$	1.22			$	0.92			$	0.83			$	0.42			$	0.55
Diluted		$	1.22			$	0.92			$	0.83			$	0.41			$	0.48
Other financial data:
Distributions per common unit(3)		$	1.825			$	1.698			$	1.540			$	1.470			$	1.360
Commodity hedging income (loss) (4)		$	10,257			$	1,095			$	448			$	(619	)		$	(51,344	)

		As of December 31,
		2006				2005				2004				2003				2002
Financial position data: (1)
Total assets		$	13,989,718			$	12,591,016			$	11,315,461			$	4,802,814			$	4,230,272
Long-term and current maturities of debt (5)		$	5,295,590			$	4,833,781			$	4,281,236			$	2,139,548			$	2,246,463
Partners’ equity (6)		$	6,480,233			$	5,679,309			$	5,328,785			$	1,705,953			$	1,200,904
Total units outstanding (excluding treasury) (6)			432,408				389,861				364,786				217,780				183,810

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

For the years ended December 31, 2006, 2005 and 2004.

     The following information should be read in conjunction with our consolidated financial statements and our accompanying notes listed in the Index to Consolidated Financial Statements on page F-1 of this annual report. Our discussion and analysis includes the following:

	•		Overview of Business.
	•		Results of Operations – Discusses material year-to-year variances in our Consolidated Statements of Operations.
	•		Liquidity and Capital Resources – Addresses available sources of liquidity and analyzes cash flows.
	•		Critical Accounting Policies – Presents accounting policies that are among the most significant to the portrayal of our financial condition and results of operations.
	•		Other Items – Includes information related to contractual obligations, off-balance sheet arrangements, related party transactions, recent accounting pronouncements and similar disclosures.

     This discussion contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “believe,” “may” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner 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.

     As generally used in the energy industry and in this discussion, 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 decatherms
		MMBbls		=		million barrels
		MMBtus		=		million British thermal units
		MMcf		=		million cubic feet
		Mcf		=		thousand cubic feet
		TBtu		=		trillion British thermal units

     Our financial statements have been prepared in accordance with accounting standards generally accepted in the United States of America (“GAAP”).

Overview of Business

     We are a North American midstream energy company providing a wide range of services to producers and consumers of natural gas, natural gas liquids (“NGLs”), and crude oil, and certain petrochemicals. In addition, we are an industry leader in the development of pipeline and other midstream energy infrastructure in the continental United States and Gulf of Mexico. We are a publicly traded Delaware limited partnership formed in 1998, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.”

     We conduct substantially all of our business through our Operating Partnership. We are owned 98% by our limited partners and 2% by our general partner, referred to as Enterprise Products GP. Enterprise Products GP is owned 100% by Enterprise GP Holdings, a publicly traded affiliate listed on the 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.

     Our midstream energy 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: 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 technologies employed) and products produced and/or sold.

Recent Developments

     The following information highlights our significant developments since January 1, 2006 through the date of this filing. For additional information regarding the capital projects and acquisitions highlighted below, see “Capital Spending – Significant Recently Announced Growth Capital Projects” included within this Item 7.

	•		In February 2007, Duncan Energy Partners L.P. (“Duncan Energy Partners”), a consolidated subsidiary of ours, completed an underwritten initial public offering of 14,950,000 of its common units. We formed Duncan Energy Partners as a Delaware limited partnership to acquire ownership interests in certain of our midstream energy businesses. For additional information regarding Duncan Energy Partners, see “Other Items – Initial Public Offering of Duncan Energy Partners” included within this Item 7.
	•		In December 2006, we purchased all of the membership interests in Piceance Creek Pipeline, LLC (“Piceance Creek Pipeline”) from an affiliate of the EnCana Corporation (“EnCana”) for $100 million. The assets of Piceance Creek Pipeline consist primarily of a recently constructed 48-mile natural gas gathering pipeline (the “Piceance Creek Gathering System”) located in the Piceance Basin of northwest Colorado. This pipeline will connect to our Meeker natural gas processing plant, which is currently under construction.
	•		In December 2006, Standard & Poor’s raised its credit rating of our Operating Partnership from BB+ to BBB-, which is investment grade, with a stable outlook. As a result of this change, all of the senior unsecured credit ratings of our Operating Partnership are currently at an investment grade level.
	•		In November 2006, we entered into a 30-year agreement with an affiliate of Exxon Mobil Corporation (“ExxonMobil”), to provide gathering, compression, treating and conditioning services for natural gas produced as part of a development program planned by ExxonMobil in the Piceance Basin in Colorado. Under the terms of the agreement, ExxonMobil’s natural gas production from its Piceance Development Project, which encompasses more than 29,000 acres in Rio Blanco County, Colorado, will be dedicated to us. The fee-based agreement

			includes an option for us to recover NGLs beyond those extracted to condition the gas to meet downstream pipeline specifications.
			To provide these services, we expect to invest approximately $185 million to construct new plant and pipeline facilities to compress the natural gas, treat it to remove impurities, extract NGLs, and deliver gas to the various pipeline transmission systems that serve the region. Construction of the facilities will begin after the receipt of the necessary permits and approvals and is expected to be completed in late 2008.
	•		In November 2006, we announced an expansion of our Texas Intrastate Pipeline with the construction of a 178-mile pipeline (the “Sherman Extension”) that will transport up to 1.1 Bcf/d of natural gas from the growing Barnett Shale area of North Texas. This new pipeline is expected to cost $424.6 million, most of which will be spent in 2008, and be placed in service during the fourth quarter of 2008.
	•		In October 2006, we signed definitive agreements with producers to construct, own and operate an offshore oil pipeline that will provide firm gathering services from the Shenzi production field located in the Southern Green Canyon area of the central Gulf of Mexico.
	•		In September 2006, we sold 12,650,000 of our common units in an underwritten public offering, which generated net proceeds of approximately $320.8 million.
	•		During the third quarter of 2006, the Operating Partnership sold $550 million in principal amount of fixed/floating unsecured junior subordinated notes due 2066 (the “Junior Subordinated Notes A”). For additional information regarding this issuance of debt, see “Liquidity and Capital Resources – Debt Obligations” included within this Item 7.
	•		In August 2006, we became a joint venture partner with TEPPCO involving its Jonah Gas Gathering Company (“Jonah”). Jonah owns the Jonah Gathering System, located in the Greater Green River Basin of southwestern Wyoming. The Jonah Gathering System gathers and transports natural gas produced from the Jonah and Pinedale fields to regional natural gas processing plants, including our Pioneer plant, and major interstate pipelines that deliver natural gas to end-use markets. As part of this new joint venture, we and TEPPCO are significantly expanding the Jonah Gathering System (the Phase V expansion project).
	•		In August 2006, we purchased a 220-mile NGL pipeline extending from Corpus Christi, Texas to Pasadena, Texas from ExxonMobil Pipeline Company. The total purchase price for this asset was $97.7 million in cash. This pipeline (in combination with others to be constructed or acquired) will be used to transport NGLs from our South Texas natural gas processing plants to our Mont Belvieu fractionation facilities. Duncan Energy Partners acquired an indirect 66% interest in this pipeline asset on February 5, 2007.
	•		In August 2006, our wholly owned subsidiary, Mid-America Pipeline Company LLC (“Mid-America”), executed new long-term transportation agreements with all but one of its current shippers on its Rocky Mountain pipeline pursuant to terms and conditions of Mid-America’s open season tariff that was accepted by the Federal Energy Regulatory Commission effective August 6, 2006. Under the terms of the new agreements, shippers have committed to transport all of their current and future NGL production from the Rocky Mountains through the Mid-America Pipeline System to either our Hobbs fractionator (expected to be operational by mid-2007) or to Mont Belvieu, Texas via our Seminole Pipeline for a minimum of 10 years and up to a maximum of 20 years. Based on shipper production forecasts and current NGL extraction rates, we expect that these new agreements will fully utilize our Mid-America Pipeline System, including the 50 MBPD Phase I Expansion expected to be placed in-service during the third quarter of 2007.
	•		In July 2006, we signed long-term agreements with CenterPoint Energy Resources Corp. (“CenterPoint Energy”) to provide firm natural gas transportation and storage services to its

			natural gas utility, primarily in the Houston, Texas metropolitan area. We will provide CenterPoint Energy with an estimated 14 Bcf per year of natural gas beginning in April 2007. Our deliveries to CenterPoint Energy through these new contracts will mark the first time that we have had the opportunity to serve the growing Houston area natural gas market. We are already the primary natural gas service provider to the San Antonio and Austin, Texas markets.
	•		In July 2006, we acquired the Encinal and Canales natural gas gathering systems and their related gathering and processing contracts and other amounts that comprised the South Texas natural gas transportation and processing business of Cerrito Gathering Company, Ltd., an affiliate of Lewis Energy Group, L.P. (“Lewis”). The aggregate value of total consideration we paid or issued to complete this business combination (referred to as the “Encinal acquisition”) was $326.3 million, which includes $145.2 million in cash paid to Lewis and the issuance of 7,115,844 of our common units to Lewis.
	•		In April 2006, we announced plans to expand our Houston Ship Channel NGL import and export facility and related pipeline and other assets to accommodate an expected increase in throughput volumes.
	•		In March 2006, we purchased the Pioneer natural gas processing plant and certain related natural gas processing rights from TEPPCO for $38.2 million in cash.
	•		In March 2006, we announced plans to expand our petrochemical assets located in southeast Texas. The plans include the construction of a new propylene fractionator at our Mont Belvieu, Texas facility and the expansion of two refinery grade propylene pipelines.
	•		In March 2006, we sold 18,400,000 of our common units in a public offering, which generated net proceeds of approximately $430 million.
	•		In January 2006, we announced the execution of a minimum 15-year natural gas processing agreement with an affiliate of EnCana. Under this agreement, we have the right to process up to 1.3 Bcf/d of EnCana’s natural gas production from the Piceance Basin area of western Colorado. To accommodate this production, we began construction of the Meeker natural gas processing facility in Rio Blanco County, Colorado. In addition, we will construct a 50-mile NGL pipeline that will connect our Meeker processing facility to our Mid-America Pipeline System.

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. We believe that we are positioned to continue to grow our system of assets through the construction of new facilities and to capitalize on expected future production increases from such areas as the Piceance Basin of western Colorado, the Greater Green River Basin in Wyoming, Barnett Shale in North Texas, and the deepwater Gulf of Mexico.

     Management continues to analyze potential acquisitions, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions. 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.

     Based on information currently available, we estimate our consolidated capital spending for 2007 will approximate $1.9 billion, which includes estimated expenditures of $1.7 billion for growth capital projects and acquisitions and $0.2 million for sustaining capital expenditures.

     Our forecast of consolidated capital expenditures is based on our strategic operating and growth plans, which are dependent upon our ability to generate the required funds from either operating cash flows or from other means, including borrowings under debt agreements, issuance of equity, and potential divestitures of certain assets to third and/or related parties. Our forecast of capital expenditures may change due to factors beyond our control, such as weather related issues, changes in supplier prices or adverse economic conditions. Furthermore, our forecast may change as a result of decisions made by management 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 a 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 the Year Ended December 31,
		2006				2005				2004
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
Encinal acquisition, including non-cash equity consideration		$	326,309			$	—				—
Piceance Creek acquisition			100,000				—				—
NGL underground storage and terminalling assets purchased from Ferrellgas			—				145,522				—
Indirect interests in the Indian Springs natural gas gathering and processing assets			—				74,854				—
Additional ownership interests in Dixie Pipeline Company (“Dixie”)			12,913				68,608				—
Additional ownership interests in Mid-America and Seminole pipeline systems			—				25,000				—
Other business combinations and asset purchases			18,390				12,618				85,851
Total			457,612				326,602				3,635,618
Capital spending for property, plant and equipment:
Growth capital projects, net			1,148,123				719,372				113,759
Sustaining capital projects			132,455				98,077				33,169
Total			1,280,578				817,449				146,928
Capital spending attributable to unconsolidated affiliates:
Investment in and advances to Jonah Gas Gathering Company			120,132
Other investments in and advances to unconsolidated affiliates			7,290				88,044				64,412
Total			127,422				88,044				64,412
Total capital spending		$	1,865,612			$	1,232,095			$	3,846,958

     Our capital spending for growth capital projects (as presented in the preceding table) are net of amounts we received from third parties as contributions in aid of our construction costs. Such contributions were $60.5 million, $47.0 million and $8.9 million during 2006, 2005 and 2004, respectively. On certain of our capital projects, third parties are 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.

     At December 31, 2006, we had $239.0 million in outstanding purchase commitments. These commitments primarily relate to growth capital projects in the Rocky Mountains that are expected to be

placed in service in 2007 and the Shenzi Oil Export Pipeline Project (see below), which is expected to be completed in 2009.

Significant Recently Announced Growth Capital Projects

     The following information summarizes our significant growth capital projects as of February 15, 2007. The capital spending amount noted for each project includes accrued expenditures and capitalized interest through December 31, 2006. The forecast amount noted for each project includes a provision for estimated capitalized interest.

     Piceance Creek Acquisition. In December 2006, we purchased all of the membership interests in Piceance Creek from an affiliate of EnCana for $100 million. The assets of Piceance Creek consist primarily of the Piceance Creek Gathering System. As part of the transaction, EnCana signed a long-term, fixed-fee gathering contract and dedicated significant production to the system for the life of the associated lease holdings. The new Piceance Creek Gathering System has a transportation capacity of 1.6 Bcf/d and extends from a connection with EnCana’s Great Divide Gathering System near Parachute, Colorado, northward through the Piceance Basin to our Meeker gas treating and processing complex, which is under construction. The Piceance Creek Gathering System commenced operations in January 2007.

     Current natural gas production from the Piceance Basin, which covers approximately 6,000 square miles, exceeds 1 Bcf/d from more than 4,800 wells and has been growing at an annualized rate averaging 25% over the past five years. With third party estimates suggesting 20 trillion cubic feet of undeveloped reserves, the Piceance Basin offers long-term opportunities for us to continue to expand our system to serve producers developing this extensive resource play.

     Barnett Shale Natural Gas Pipeline Project. In November 2006, we announced an expansion of our Texas Intrastate Pipeline with the construction of the Sherman Extension that will transport up to 1.1 Bcf/d of natural gas from the growing Barnett Shale area of North Texas. The Sherman Extension is supported by long-term contracts with Devon Energy Corporation, the largest producer in the Barnett Shale area, and significant indications of interest from leading producers and gatherers in the Fort Worth basin, as well as other shippers on our Texas Intrastate Pipeline system. At its terminus, the new pipeline system will make deliveries into Boardwalk Pipeline Partners L.P.’s (“Boardwalk”) Gulf Crossing Expansion Project, which will provide export capacity for Barnett Shale natural gas production to multiple delivery points in Louisiana, Mississippi and Alabama that offer access to attractive markets in the Northeast and Southeast United States. In addition, the Sherman Extension will provide natural gas producers in East Texas and the Waha area of West Texas with access to these higher value markets through our Texas Intrastate Pipeline system.

     The Sherman Extension will originate near Morgan Mill, Texas and extend through the center of the current Barnett Shale development area to Sherman, Texas. This new pipeline is expected to cost $424.6 million, most of which will be spent in 2008, and be placed in service during the fourth quarter of 2008. In addition, we have the option to acquire up to a 49% interest in Gulf Crossing Expansion Project from Boardwalk, subject to certain conditions.

     The Barnett Shale is considered to be one of the largest unconventional natural gas resource plays in North America, covering approximately 14 counties and over seven million acres in the Fort Worth basin in North Texas. Current natural gas production is estimated at 2 Bcf/d from approximately 5,500 wells. Approximately 130 rigs are currently estimated to be working to develop Barnett Shale acreage in the region. According to the United States Geological Survey, the Barnett Shale has the resource potential of approximately 26 trillion cubic feet of natural gas.

     Shenzi Oil Export Pipeline Project. In October 2006, we announced the execution of definitive agreements with producers to construct, own and operate an oil export pipeline that will provide firm gathering services from the BHP Billiton Plc-operated Shenzi production field located in the South Green Canyon area of the central Gulf of Mexico. The estimated construction cost of this new pipeline is

approximately $172.4 million. As of December 31, 2006, our capital spending with respect to the Shenzi oil pipeline project was $6.8 million.

     The Shenzi oil export pipeline will originate at the Shenzi Field, located in 4,300 feet of water at Green Canyon Block 653, approximately 120 miles off the coast of Louisiana. The 83-mile, 20-inch diameter pipeline will have the capacity to transport up to 230 MBPD of crude oil and will connect the Shenzi Field to our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System at our Ship Shoal 332B junction platform. We own a 50% interest in the Cameron Highway Oil Pipeline and a 36% interest in the Poseidon Oil Pipeline System and operate both pipelines. The Shenzi oil export pipeline will connect to a platform being constructed by BHP Billiton Plc to develop the Shenzi Field, which is expected to begin production in mid-2009.

     Jonah Joint Venture with TEPPCO and the Phase V Expansion. In August 2006, we became a joint venture partner with TEPPCO in its Jonah subsidiary, which owns the Jonah Gathering System, located in the Greater Green River Basin of southwestern Wyoming. The Jonah Gathering System currently gathers and transports approximately 1.5 Bcf/d (or 85%) of natural gas produced from over 1,100 wells in the Jonah and Pinedale fields to regional natural gas processing plants, including our Pioneer plant, and major interstate pipelines that deliver natural gas to end-use markets.

     Prior to entering into the Jonah joint venture, we managed the construction of the Phase V expansion and funded the initial construction costs under a letter of intent we entered into in February 2006. In connection with the joint venture arrangement, we and TEPPCO plan to continue the Phase V expansion, which is expected to increase the capacity of the Jonah Gathering System from 1.5 Bcf/d to 2.3 Bcf/d and to significantly reduce system operating pressures, which is anticipated to lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which is expected to increase the system gathering capacity to 2.0 Bcf/d, is projected to be completed in the first quarter of 2007 at an estimated cost of approximately $302.0 million. The second portion of the Phase V expansion is expected to cost approximately $142.0 million and be completed by the end of 2007. As of December 31, 2006, capital spending with respect to the overall Phase V Expansion (on a 100% basis) was $233.7 million.

     We will continue to manage the Phase V construction project. TEPPCO was entitled to all distributions from the joint venture until specified milestones were achieved, at which point, we became entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. After subsequent milestones are achieved, we and TEPPCO will share distributions based on a formula that takes into account the respective capital contributions of the parties, including expenditures by TEPPCO prior to the expansion. From August 1, 2006, we and TEPPCO share equally in the construction costs of the Phase V expansion.

     As of December 31, 2006, TEPPCO reimbursed us $109.4 million for 50% of the Phase V expansion cost incurred through November 29, 2006 (including carrying costs of $1.3 million). We had a receivable of $8.7 million from TEPPCO at December 31, 2006 for costs incurred through December 31, 2006. Upon completion of the expansion project and based on the formula in the joint venture partnership agreement, we expect to own an interest in Jonah of approximately 20%, with TEPPCO owning the remaining 80%. We will operate the system. See Item 13 of this annual report for additional information regarding our relationship with TEPPCO.

     DEP South Texas NGL Pipeline System. In August 2006, we acquired a 220-mile pipeline from ExxonMobil Pipeline Company for $97.7 million in cash. This pipeline originates in Corpus Christi, Texas and extends to Pasadena, Texas. This pipeline segment was expanded (the “Phase I expansion”) by (i) the construction of 45 miles of pipeline laterals to connect the system to our Armstrong and Shoup NGL fractionation facilities; (ii) the short-term lease from TEPPCO of a 11-mile interconnecting pipeline extending from Pasadena, Texas to Baytown, Texas; and (iii) the purchase of an additional 10-mile pipeline from TEPPCO that will connect the leased TEPPCO pipeline to Mont Belvieu, Texas. The purchase of the 10-mile segment from TEPPCO cost $8.0 million and was completed in January 2007. The primary term of the TEPPCO pipeline lease will expire in September 2007, and will continue on a month-to-month basis

subject to customary termination provisions. Collectively, this 286-mile pipeline system will be termed the DEP South Texas NGL Pipeline. Phase I of the DEP South Texas NGL Pipeline System commenced transportation of NGLs in January 2007.

     During 2007, we will construct an additional 21 miles of pipeline (the “Phase II upgrade”) to replace (i) the 11-mile pipeline we lease from TEPPCO and (ii) certain segments of the pipeline we acquired in August 2006 from ExxonMobil Pipeline Company. The Phase II upgrade is expected to provide a significant increase in pipeline capacity and be operational during the third quarter of 2007.

     We estimate the cost of the Phase I expansion was $37.7 million, which included the $8 million we paid TEPPCO to acquire its 10-mile Baytown to Mont Belvieu pipeline. We expect the Phase II upgrade to cost an additional $28.6 million. As of December 31, 2006, our capital spending with respect to the DEP South Texas NGL Pipeline System was $117.8 million, which includes the $97.7 million we paid in August 2006.

     This pipeline system is owned by South Texas NGL Pipelines, LLC, an entity that is 66% owned by Duncan Energy Partners and 34% by our Operating Partnership. For additional information regarding Duncan Energy Partners, see “Other Items – Initial Public Offering of Duncan Energy Partners” included within this Item 7.

     Texas Intrastate Pipeline Expansion Projects. In July 2006, we signed long-term agreements with CenterPoint Energy to provide firm natural gas transportation and storage services to its one of its natural gas utilities, primarily in the Houston, Texas metropolitan area. We will provide CenterPoint Energy with an estimated 14 Bcf per year of natural gas beginning in April 2007.

     To provide these new services, we will enhance our Texas Intrastate natural gas pipeline system through a combination of pipeline and compression projects, including the expansion of our Wilson natural gas storage facility in Texas, acquisition of certain pipeline laterals located in the Houston, Texas area and the construction of eleven new city gate delivery stations.

     The total capital cost of these projects is estimated to be $112.2 million and will be completed in phases extending through 2008. As of December 31, 2006, our capital spending with respect to these natural gas pipeline projects was $13.7 million. As part of this expansion project, we purchased certain idle pipeline assets in the Houston, Texas area from TEPPCO for $11.7 million in cash in October 2006.

     Encinal Acquisition. In July 2006, we acquired the Encinal and Canales natural gas gathering systems and related gathering and processing contracts and other assets that comprised the South Texas natural gas transportation and processing business of Lewis. The aggregate value of total consideration we paid or issued to complete this business combination, referred to as the Encinal acquisition, was $326.3 million.

     The Encinal and Canales gathering systems are located in South Texas and are connected to over 1,450 natural gas production wells producing from the Olmos and Wilcox formations. The Encinal system consists of 452 miles of pipeline, which is comprised of 280 miles of pipeline we acquired from Lewis in this transaction and 172 miles of pipeline that we own and had previously leased to Lewis. The Canales gathering system is comprised of 32 miles of pipeline. Currently, natural gas volumes gathered by the Encinal and Canales systems are transported by our existing South Texas natural gas pipeline system and are processed by our South Texas natural gas processing plants.

     As part of this transaction, we acquired long-term natural gas processing and gathering dedications from Lewis. First, these gathering systems will be supported by a life of reserves gathering and processing dedication by Lewis related to its natural gas production from the Olmos formation. Second, Lewis entered into a 10-year agreement with us for the transportation of natural gas treated at its proposed Big Reef facility. This facility will treat natural gas production from the southern portion of the Edwards Trend in South Texas. Third, Lewis entered into a 10-year agreement with us for the gathering and processing of rich gas it produces from below the Olmos formation.

     The total consideration paid or granted for the Encinal acquisition is summarized in the following table (dollars in thousands):

Cash payment to Lewis		$	145,197
Fair value of our 7,115,844 common units issued to Lewis			181,112
Total consideration		$	326,309

     See Note 12 of the Notes to the Consolidated Financial Statements included under Item 8 of this annual report for our preliminary purchase price allocation related to this acquisition. As a result of our preliminary purchase price allocation, we recorded goodwill of $95.2 million, which management attributes to potential future benefits we may realize from our existing South Texas processing and NGL businesses as a result of the Encinal acquisition. Specifically, the long-term dedication rights acquired in connection with the Encinal acquisition are expected to add value to our South Texas processing facilities and related NGL businesses due to increased volumes.

     Expansion of Import and Export Capability. In April 2006, we announced an expansion of our NGL import and export terminal located on the Houston Ship Channel. This expansion project will increase offloading capability of our import facility from a maximum peak operating rate of 240 MBPD to 480 MBPD and the maximum loading rate of our export facility from 140 MBPD to 160 MBPD. As part of this expansion project, we will increase the transportation and processing capacities of certain of our assets that serve the terminal in order to accommodate the expected increase in import volumes.

     This expansion project is expected to cost approximately $62.7 million and be completed in the second quarter of 2007. As of December 31, 2006, our capital spending with respect to the expansion of import and export capabilities was $5.8 million.

     Wyoming Gas Processing Projects. In March 2006, we paid $38.2 million to TEPPCO for its Pioneer natural gas processing plant located in Opal, Wyoming and certain natural gas processing rights related to production from the Jonah and Pinedale fields located in the Greater Green River Basin in Wyoming. After completing this asset purchase, we increased the capacity of the Pioneer natural gas processing plant from 300 MMcf/d to 600 MMcf/d at an additional cost of approximately $21 million. This expansion was completed in July 2006 and enables us to process natural gas production from the Jonah and Pinedale fields that will be transported to our Wyoming facilities as a result of the processing contract rights we acquired from TEPPCO. Of the $38.2 million we paid TEPPCO to acquire the Pioneer facility, $37.8 million was allocated to the contract rights we acquired.

     In addition, to handle future production growth in the region and substantially increase NGL recoveries, we started construction of a new cryogenic natural gas processing plant in July 2006 adjacent to the Pioneer plant we acquired from TEPPCO. We expect our new natural gas processing plant, which will have the capacity to process up to 750 MMcf/d of natural gas, to be placed in service by the fourth quarter of 2007 at an expected cost of $236.2 million. As of December 31, 2006, our capital spending with respect to the new natural gas processing plant was $53.7 million.

     Expansion of Mont Belvieu Petrochemical Assets. In March 2006, we announced an expansion of our petrochemical assets in Mont Belvieu and southeast Texas. This expansion project includes (i) the construction of a fourth propylene fractionator at our Mont Belvieu complex, which will increase our propylene/propane fractionation capacity by approximately 15 MBPD, and (ii) the expansion of two refinery grade propylene gathering pipelines which will add 50 MBPD of gathering capacity into Mont Belvieu. These projects are expected to be completed by late 2007 and cost approximately $204.1 million, which includes $35.0 million we spent in December 2005 to acquire a related pipeline asset. As of December 31, 2006, our capital spending with respect to these expansion projects was $142.8 million.

     Piceance Basin Gas Processing Project. In January 2006, we announced the execution of a minimum 15-year natural gas processing agreement with an affiliate of EnCana. Under that agreement, we

have the right to process up to 1.3 Bcf/d of EnCana’s natural gas production from the Piceance Basin area of western Colorado.

     To accommodate this production, we have begun construction of the Meeker natural gas processing facility in Rio Blanco County, Colorado. This processing plant will provide us with 750 MMcf/d of natural gas processing capacity and the ability to recover up to 35 MBPD of NGLs at full rates when Phase I of construction is completed in mid-2007. In addition, we will construct an approximate 50-mile NGL pipeline that will connect our Meeker facility with our Mid-America Pipeline System. The estimated cost of Phase I of the Meeker facility and related NGL pipeline is $320.7 million. EnCana has certain guaranteed payment obligations to us and we are currently working to secure production dedications from additional producers.

     In June 2006, EnCana executed an option which requires us to build a 750 MMcf/d expansion of the Meeker facility by mid-2008 (the “Phase II” expansion). We have initiated design work on this expansion, which is expected to cost $260.6 million. This expansion will enable us to recover an additional 35 MBPD of NGLs at full rates. Under the terms of the agreement, EnCana has certain additional guaranteed payment obligations to us associated with the Phase II expansion.

     As of December 31, 2006, our capital spending with respect to our Piceance Basin gas processing projects was $137.4 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. This project is expected to cost $232.5 million and be placed in service during the third quarter of 2007. Our Hobbs NGL fractionator will process the increase in mixed NGLs resulting from our Phase I expansion of the Mid-America Pipeline System. As of December 31, 2006, our capital spending with respect to the Hobbs NGL fractionator was $110.4 million.

     Mid-America Pipeline System Projects. In January 2005, we announced an expansion (the Phase I expansion) of the Rocky Mountain segment of our Mid-America Pipeline System to accommodate expected increases in mixed NGL shipments originating from producing basins in Wyoming, Utah, Colorado and New Mexico. The Phase I expansion project will be completed in stages and will increase throughput volumes on the Rocky Mountain segment by 50 MBPD. We expect final completion of the Phase I expansion during the third quarter of 2007 at a cost of approximately $202.6 million.

     As of December 31, 2006, our capital spending with respect to the Phase I expansion project was $128.6 million, including accrued expenditures. In August 2006, we executed new long-term transportation agreements with all but one of our current shippers on the Rocky Mountain segment of the Mid-America Pipeline System that will fully utilize this additional capacity.

     In June 2005, we began engineering and design work to construct a 190-mile, 12-inch NGL pipeline that will have the capacity to move up to 67 MBPD of mixed NGLs bi-directionally between Skellytown, Texas and Conway, Kansas and an additional 48 MBPD from Skellytown, Texas to Hobbs, New Mexico. Construction of this pipeline began in the spring of 2006 and is expected to cost approximately $83.6 million and be placed in service in April 2007. As of December 31, 2006, our capital spending with respect to the Skellytown to Conway pipeline was $62.5 million.

     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 the second half of 2007.

     We constructed and own an 80% interest in the Independence Hub platform, which will be located in Mississippi Canyon Block 920, at a water depth of approximately 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. In January 2007, the Independence Hub platform sailed from its construction site in Corpus Christi, Texas to Mississippi Canyon Block 920, where it will be installed. We expect mechanical completion of the platform by mid-March 2007.

     The platform, which is estimated to cost $445.9 million, will be operated by Anadarko (one of the major producers in the Atwater Valley Producers Group), and is designed to process production from its anchor fields and has excess payload capacity to support ten additional pipeline risers. As of December 31, 2006, our 80% share of capital spending with respect to the Independence Hub platform was $344.8 million.

     During the third quarter of 2006, we completed construction of our 134-mile Independence Trail natural gas pipeline system, which has a throughput capacity of 1 Bcf/d of natural gas and will transport production from our Independence Hub platform to the Tennessee Gas Pipeline. This pipeline system and a related junction platform (under construction) are estimated to cost $281.3 million. We own 100% of the Independence Trail pipeline. As of December 31, 2006, our capital spending with respect to the Independence Trail pipeline and related junction platform was $271.3 million, including accrued expenditures.

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.

     We spent approximately $64.6 million to comply with these programs during 2006, of which $26.4 million was recorded as an operating expense and the remaining $38.2 million was capitalized. During 2005, we spent approximately $42.2 million to comply with these programs, of which $25.0 million was recorded as an operating expense, and the remaining $17.2 million was capitalized.

     We expect our net cash outlay for pipeline integrity program expenditures to approximate $48.0 million for 2007. Our forecast is net of certain costs we expect to recover from El Paso in connection with an indemnification agreement. 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. In 2006, we recovered $13.7 million from El Paso related to our 2005 expenditures. During 2007, we expect to recover $29.1 million from El Paso related to our 2006 expenditures, which leaves a remainder of $7.3 million reimbursable by El Paso for 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-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 GAAP financial measure most directly comparable to total segment gross operating margin is operating income. Our non-GAAP financial measure of total segment gross operating margin should not be considered as an alternative to GAAP operating income.

     We define total (or consolidated) segment gross operating margin as operating income before depreciation, amortization and accretion 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. Intercompany accounts and transactions are eliminated in consolidation.

     We include earnings from equity method 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 and/or suppliers. 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. As circumstances dictate, we may increase our ownership interest in equity investments, which could result in their subsequent consolidation into our operations.

     For additional information regarding our business segments, see Note 16 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 annual and quarterly industry index prices for natural gas, crude oil and selected NGL and petrochemical products for the periods presented.

																														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)
2004 Averages		$	6.13			$	41.45			$	0.50			$	0.74			$	0.88			$	0.88			$	1.00			$	0.33			$	0.29
2005 Averages		$	8.64			$	56.47			$	0.62			$	0.91			$	1.09			$	1.15			$	1.26			$	0.42			$	0.37
2006
1st Quarter		$	9.01			$	63.35			$	0.57			$	0.94			$	1.20			$	1.27			$	1.38			$	0.45			$	0.40
2nd Quarter		$	6.80			$	70.53			$	0.68			$	1.05			$	1.22			$	1.26			$	1.52			$	0.50			$	0.44
3rd Quarter		$	6.58			$	70.44			$	0.76			$	1.10			$	1.28			$	1.30			$	1.53			$	0.51			$	0.46
4th Quarter		$	6.56			$	60.03			$	0.62			$	0.95			$	1.11			$	1.12			$	1.31			$	0.44			$	0.35
2006 Averages		$	7.24			$	66.09			$	0.66			$	1.01			$	1.20			$	1.24			$	1.44			$	0.47			$	0.41