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, 2007

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 (Address of Principal Executive Offices)		77002 (Zip Code)

(713) 381-6500
(Registrant’s Telephone Number, Including Area Code)

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

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

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

Yes þ No o

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

Yes o No þ

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

Yes þ No o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ						Accelerated filer o
Non-accelerated filer   o		(Do not check if a smaller reporting company)				Smaller Reporting Company 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, 2007, based on the closing price of such equity securities in the daily composite list for transactions on the New York Stock Exchange, was approximately $9.1 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 435,297,303 common units of EPD outstanding at February 1, 2008.

 

 

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.			49
Item 3.		Legal Proceedings.			49
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.			84
Item 8.		Financial Statements and Supplementary Data.			89
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.			171
Item 9A.		Controls and Procedures.			171
Item 9B.		Other Information.			175
		PART III
Item 10.		Directors, Executive Officers and Corporate Governance.			175
Item 11.		Executive Compensation.			181
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.			190
Item 13.		Certain Relationships and Related Transactions, and Director Independence.			194
Item 14.		Principal Accountant Fees and Services.			203
		PART IV
Item 15.		Exhibits and Financial Statement Schedules.			204
Signatures					210
Index to Exhibits
Computation of Ratio of Earnings to Fixed Charges
List of Subsidiaries
Consent of Deloitte & Touche LLP
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 1350
Certification Pursuant to Section 1350

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.

          References to “EPO” mean Enterprise Products Operating LLC as successor in interest by merger to 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” mean Duncan Energy Partners L.P., which is a consolidated subsidiary of EPO. Duncan Energy Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “DEP.” References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by EPO.

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

          References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded affiliate, the units of which are listed on the NYSE under the ticker symbol “EPE.” Enterprise GP Holdings 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 affiliate, the common units of which are listed on the NYSE under the ticker symbol “TPP.” References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by Enterprise GP Holdings.

          References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETE.” The general partner of Energy Transfer Equity is LE GP, LLC (“LE GP”). On May 7, 2007, Enterprise GP Holdings acquired non-controlling interests in both LE GP and Energy Transfer Equity.

          References to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”) and EPE Unit III, L.P. (“EPE Unit III”), collectively, which are private company affiliates of EPCO, Inc. See Note 25 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding the formation of Enterprise Unit L.P. in February 2008.

          References to “EPCO” mean EPCO, Inc. and its wholly-owned private company affiliates, which are related party affiliates to all of the foregoing named entities.

          We, EPO, Duncan Energy Partners, DEP GP, EPGP, Enterprise GP Holdings, EPE Holdings, TEPPCO and TEPPCO GP are affiliates under the common control of Dan L. Duncan, the Group Co-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,” “seek,” “goal,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,” “potential” 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 EPO. Our principal executive offices are located at 1100 Louisiana, 10^th Floor, Houston, Texas 77002, our telephone number is (713) 381-6500 and our website is www.epplp.com.

          We are a publicly traded Delaware limited partnership formed in 1998, the common units of which are listed on the NYSE under the ticker symbol “EPD.” We are owned 98% by our limited partners and 2% by our general partner, EPGP. 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.”

Business Strategy

          We operate an integrated network of midstream energy assets that includes: natural gas gathering, treating, processing, transportation and storage; NGL fractionation (or separation), transportation, storage and import and export terminalling; crude oil transportation; offshore production platform services; and petrochemical transportation and services. Our business strategies are to:

	§		capitalize on expected increases in natural gas, NGL and crude oil production resulting from development activities in the Rocky Mountains and U.S. Gulf Coast regions, including the Gulf of Mexico;
	§		capitalize on expected demand growth for natural gas, NGLs, crude oil and refined products;
	§		maintain a 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

          For information regarding our 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.

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 2007, 2006 and 2005, our largest customer was The Dow Chemical Company and its affiliates, which accounted for 6.9%, 6.1% and 6.8%, respectively, of our consolidated revenues.

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

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

          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 13,758 miles including our 7,808-mile Mid-America Pipeline System, (iii) NGL and related product storage facilities and (iv) 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, as 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 26 processing plants located in Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming. Natural gas produced at the wellhead especially 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 (a combination of percent-of-liquids and fee-based contract terms) 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 earn 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 and generally bears the natural gas cost for shrinkage and plant fuel. 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 natural gas equivalent 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. For information regarding our use of commodity financial instruments, see “Quantitative and Qualitative Disclosures About Market Risks” included under Item 7A of this annual report.

          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 13,758 miles of NGL pipelines, 154.9 million barrels of working capacity for underground NGL and related product storage and two import/export facilities.

          Our NGL pipelines transport mixed NGLs and other hydrocarbons from natural gas processing facilities, refineries and import terminals to fractionation plants and storage facilities; 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 storage capacity in our underground caverns. The customers pay reservation fees based on the quantity of capacity reserved rather than the actual quantity 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 fractionation 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 on 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 eight 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 represents 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 originating 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 on a seasonal basis from March through November 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 natural gas processing assets of our NGL Pipelines & Services business segment at February 1, 2008.

						Net Gas				Total Gas
				Our		Processing				Processing
				Ownership		Capacity				Capacity
Description of Asset		Location(s)		Interest		(Bcf/d) (1)				(Bcf/d)
Natural gas processing facilities:
Pioneer (2)		Wyoming		100%			1.35				1.35
Meeker (3)		Colorado		100%			0.75				0.75
Toca		Louisiana		63.9%			0.70				1.10
Chaco		New Mexico		100%			0.65				0.65
North Terrebonne		Louisiana		48.8%			0.63				1.30
Calumet		Louisiana		32.0%			0.51				1.60
Neptune		Louisiana		66%			0.43				0.65
Pascagoula		Mississippi		40%			0.40				1.50
Yscloskey		Louisiana		18.3%			0.34				1.85
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 (11 facilities) (4)		Texas, New Mexico, Louisiana		Various (5)			1.27				3.44
Total processing capacities							8.38				15.54

          At the core of our natural gas processing business are 26 processing plants located in Texas, Louisiana, Mississippi, New Mexico, Colorado 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, Meeker and Pioneer plants and all of the Texas facilities. On a weighted-average basis, utilization rates for these assets were 63%, 56% and 53% during the years ended December 31, 2007, 2006 and 2005, respectively. These rates reflect the periods in which we owned an interest in such facilities.

          Our NGL marketing activities utilize a fleet of approximately 445 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 table summarizes the significant NGL pipelines and related storage assets of our NGL Pipelines & Services business segment at February 1, 2008.

Useable

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%

7,808

Dixie Pipeline

South and Southeastern U.S.

74.2% (1)

1,371

Seminole Pipeline

Texas

90% (2)

1,342

EPD South Texas NGL System

Texas

100%

1,039

Louisiana Pipeline System

Louisiana

Various (3)

612

Promix NGL Gathering System

Louisiana

50%

364

DEP South Texas NGL Pipeline System

Texas

100% (4)

286

Houston Ship Channel

Texas

100%

266

Lou-Tex NGL

Texas, Louisiana

100%

205

Others (5 systems) (5)

Various

Various

465

Total miles

13,758

NGL and related product storage facilities by state:

Texas (6)

124.5

Louisiana

15.3

Mississippi

5.7

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

9.4

Total capacity (7)

154.9

          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 1,583 MBPD, 1,450 MBPD and 1,360 MBPD during the years ended December 31, 2007, 2006 and 2005, 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 2,785-mile Rocky Mountain pipeline, the 2,771-mile Conway North pipeline and the 2,252-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. During 2007, the Rocky Mountain pipeline’s capacity was increased by 50 MBPD. 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, which completed an expansion in 2007, connects the Conway hub with Kansas refineries and transports NGLs to and from Conway, Kansas to the Hobbs hub. The Mid-America Pipeline System interconnects with our Seminole Pipeline and Hobbs NGL fractionator and storage facility at the Hobbs hub. We also own fifteen unregulated propane terminals that are an integral part of the Mid-America Pipeline System.
			During 2007, approximately 51% 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, the Piceance Basin of Colorado, the Uintah Basin of Colorado and Utah 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 contributed a direct 66% equity interest in South Texas NGL Pipelines, LLC (“South Texas NGL”), our subsidiary that owns the DEP South Texas NGL Pipeline System, to Duncan Energy Partners effective February 1, 2007. We own the remaining 34% direct equity interest in South Texas NGL. For additional information regarding Duncan Energy Partners, see “Other Items – Initial Public Offering of Duncan Energy Partners” included under Item 7 of this annual report.
	§		The Houston Ship Channel pipeline system is a collection of pipelines extending from our Houston Ship Channel import/export facility and Morgan’s Point facility to Mont Belvieu, Texas.

			This system is used to deliver NGL products to third-party petrochemical plants and refineries as well as to deliver feedstocks to our Mont Belvieu facilities.
	§		The Lou-Tex NGL pipeline system is used to provide transportation services for NGLs and refinery grade propylene between the Louisiana and Texas markets. We also use this pipeline to transport mixed NGLs from certain of our Louisiana gas processing plants to our Mont Belvieu NGL fractionation facility.

          Our NGL and related product storage facilities are integral parts of our pipeline and other operations. In general, these underground storage facilities are used to store NGLs and petrochemical products for us and our customers. Our underground storage facilities include locations in Arizona and Kansas 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.

          We contributed a direct 66% equity interest in our subsidiary, Mont Belvieu Caverns, LLC (“Mont Belvieu Caverns”), to Duncan Energy Partners on February 5, 2007. We own the remaining 34% direct equity 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. In 2007, we modified certain wells at our Mont Belvieu Caverns’ facility to enable us to also store refined products such as motor gasoline and diesel fuel. For information regarding our ongoing Mont Belvieu storage well optimization projects, see “Liquidity and Capital Resources – Capital Spending” included under Item 7 of this annual report.

          The following table summarizes the significant NGL fractionation assets of our NGL Pipelines & Services business segment at February 1, 2008.

						Net				Total
				Our		Plant				Plant
				Ownership		Capacity				Capacity
Description of Asset		Location(s)		Interest		(MBPD) (1)				(MBPD)
NGL fractionation facilities:
Mont Belvieu		Texas		75%			178				230
Shoup and Armstrong		Texas		100%			87				87
Hobbs		Texas		100%			75				75
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							519				702

 

          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.
	§		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 Hobbs NGL fractionation facility is located in Gaines County, Texas, where it serves petrochemical end users and refineries in West Texas, New Mexico and California. In addition, the Hobbs facility can supply exports to northern Mexico through existing pipeline infrastructure. The Hobbs facility receives mixed NGLs from several major supply basins including Mid-Continent, Permian Basin, San Juan Basin and the Rocky Mountain Overthrust. The facility is strategically located at the interconnect of our Mid-America Pipeline System and Seminole Pipeline, providing us flexibility to supply the nation’s largest NGL hub at Mont Belvieu, Texas as well as access to the second-largest NGL hub at Conway, Kansas.
	§		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, Venice 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 364-mile Promix NGL Gathering System, Promix owns five NGL storage caverns and a barge loading facility that is integral to its operations.
	§		The BRF facility fractionates 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 80%, 75% and 74% during the years ended December 31, 2007, 2006 and 2005, 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 own an import and export facility located on land we lease from Oiltanking Houston LP (“OTTI”). In June 2007, we completed an expansion of our OTTI facilities, which significantly increased our loading and offloading capabilities. Our OTTI import facility can now offload NGLs from tanker vessels at rates up to 20,000 barrels per hour depending on the product. Our OTTI export facility can now load cargoes of refrigerated propane and butane onto tanker vessels at rates up to 6,700 barrels per hour. Previously, our offloading rate was up to 10,000 barrels per hour (depending on product) and our maximum loading rate was 5,000 barrels per hour. In addition to our OTTI facilities, 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 84 MBPD, 127 MBPD and 119 MBPD for 2007, 2006 and 2005, respectively.

     Onshore Natural Gas Pipelines & Services

          Our Onshore Natural Gas Pipelines & Services business segment includes approximately 17,758 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. We own two salt dome natural gas storage facilities located in Mississippi and lease natural gas storage facilities located in Texas and Louisiana. This segment also includes our natural gas marketing activities.

          Onshore natural gas pipelines and related natural gas marketing. 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., and 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.

          We entered the natural gas marketing business in 2001 when we acquired the Acadian Gas System. In 2007, we initiated an expansion of this marketing business to leverage off our other natural gas pipeline assets. Our natural gas marketing activities generate revenues from the sale and delivery of natural gas obtained primarily from (i) third party well-head purchases, (ii) our natural gas processing plants or (iii) the open market. In general, our natural gas sales contracts utilize market-based pricing and can incorporate pricing differentials for factors such as delivery location. We expect our natural gas marketing business to continue to grow in the future. Our consolidated revenues from this business were $1.6 billion, $1.2 billion and $1.1 billion for the years ended December 31, 2007, 2006 and 2005, respectively.

          We are exposed to commodity price risk to the extent that we take title to natural gas volumes through our natural gas marketing activities or through certain contracts on our intrastate natural gas pipelines. In addition, our San Juan, Waha, Carlsbad and Jonah pipelines 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 95% 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. For information regarding our use of commodity financial instruments, see “Quantitative and Qualitative Disclosures About Market Risks” included under Item 7A of this annual report.

          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 natural gas-fired power generation facilities increase output to meet residential and commercial demand for electricity for air conditioning and in the winter months natural gas is needed as fuel for residential and commercial heating. Likewise, this seasonality also impacts the timing of injections and withdrawals at our natural gas storage facilities.

          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 1, 2008.

										Approx. Net
				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% (1)			6,976				5,155
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				1,149
Jonah Gathering System		Wyoming		19.4%			643				387
Waha Gathering System		Texas, New Mexico		100%			465				380
Carlsbad Gathering System		Texas, New Mexico		100%			919				220
Alabama Intrastate System		Alabama		100%			408				200
Encinal Gathering System		Texas		100%			449				143
Other (6 systems) (3)		Texas, Mississippi		Various (4)			743
Total miles							17,758
Natural gas storage facilities:
Petal		Mississippi		100%											14.1
Hattiesburg		Mississippi		100%											4.0
Wilson		Texas		Leased (5)											6.4
Acadian		Louisiana		Leased (6)											3.0
Total gross capacity															27.5

          On a weighted-average basis, aggregate utilization rates for our onshore natural gas pipelines were approximately 64%, 71% and 73% during the years ended December 31, 2007, 2006 and 2005, respectively. The utilization rate for 2007 excludes our Piceance Creek Gathering System, which operated at an average utilization rate of 24% during 2007 as volumes ramped-up on this system. Our utilization rates reflect the periods in which we owned an interest in such assets, or, for recently constructed assets, since the dates such assets were placed into service.

          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 as well as to connections with intrastate and interstate pipelines. 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 6,106-mile Enterprise Texas pipeline system, the 229-mile TPC Offshore gathering system and the 641-mile Channel pipeline system. The leased Wilson natural gas storage facility is an integral part of the Texas Intrastate System.
			In November 2006, we announced an expansion of our Texas Intrastate System 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. For information regarding this expansion projects, see “Liquidity and Capital Resources — Capital Spending” included under Item 7 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. We acquired this pipeline 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 1.5 Bcf/d Meeker natural gas treating and processing complex, which completed its first phase of construction in October 2007. We placed the Piceance Creek Gathering System into service in January 2007 and it currently transports approximately 520 MMcf/d of natural gas. With connectivity to EnCana’s Great Divide Gathering System, our Piceance Creek Gathering System has access to natural gas production from the southern portion of the Piceance basin, including production from EnCana’s Mamm Creek field.
	§		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 10,630 producing wells in the San Juan Basin and delivers the natural gas to natural gas processing facilities, including our Chaco facility.
			In November 2007, we and the Jicarilla Apache Nation announced the formation of a joint venture to own and operate natural gas gathering assets located on or near Jicarilla Apache Nation reservation lands. For additional information regarding this new joint venture, see “Recent Developments” included under Item 7 of this annual report.
	§		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, LLC (“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 equity interest in Acadian Gas. For additional information regarding Duncan Energy Partners, see “Other Items — Initial Public Offering of Duncan Energy Partners” included under Item 7 of this annual report. Acadian Gas owns a 49.5% indirect interest in the Evangeline pipeline.
	§		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. Our ownership in this gathering system is through our 19.4% equity method investment in Jonah Gas Gathering Company, which we acquired from TEPPCO in August 2006. We completed the first portion of the Phase V expansion the Jonah Gathering System in July 2007.

Currently the gross gathering capacity of this system is 2.0 Bcf/d (net to our interest, 387 MMcf/d) and is expected to increase to 2.4 Bcf/d upon the completion of the final stage of this expansion in April 2008. For additional information regarding this joint venture arrangement with TEPPCO, see Item 13 of this annual report.

	§		The Waha and Carlsbad Gathering Systems (formerly our Permian Basin System) gather natural gas from wells in the Permian Basin region of Texas and New Mexico and deliver natural gas into the El Paso Natural Gas, Transwestern and Oasis pipelines.
	§		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 in south Texas 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.

We are developing a new natural gas storage cavern located at our Petal facility. The new cavern is designed to store approximately 7.9 Bcf of natural gas, of which approximately 5.0 Bcf will be working gas capacity and 2.9 Bcf will be the base gas requirements needed to support minimum pressures. This expansion project was approved by the FERC and is projected to commence operations during the second quarter of 2008. We have long-term, binding precedent agreements on the majority of the new capacity.

          We are developing additional natural gas storage capacity at our Wilson facility. In addition, we are constructing various natural gas gathering pipelines and related assets in the Rocky Mountains region in support of long-term service agreements with major producers. For information regarding these expansion projects, see “Liquidity and Capital Resources — Capital Spending” included under Item 7 of this annual report.

     Offshore Pipelines & Services

          Our Offshore Pipelines & Services business segment includes (i) approximately 1,555 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 914 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 (generally 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 served by 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. Our Independence Hub and Marco Polo offshore platforms earn a significant amount of demand revenues. The Independence Hub platform will earn $55.2 million of demand revenues annually through March 2012. The Marco Polo platform will earn $25.2 million of demand revenues annually through April 2009.

          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 1, 2008, 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:
High Island Offshore System		100%			291								1,800
Viosca Knoll Gathering System		100%			172								1,000
Independence Trail (1)		100%			134								1,000
Green Canyon Laterals		Various (2)			95								599
Anaconda Gathering System (3)		100%			137								550
Phoenix Gathering System		100%			77								450
Falcon Natural Gas Pipeline		100%			14								400
Manta Ray Offshore Gathering System		25.7%			250								206
Nautilus System		25.7%			101								154
VESCO Gathering System		13.1%			260								105
Nemo Gathering System		33.9%			24								102
Total miles					1,555
Offshore crude oil pipelines:
Cameron Highway Oil Pipeline		50%			374												250
Poseidon Oil Pipeline System		36%			372												144
Allegheny Oil Pipeline		100%			43												140
Marco Polo Oil Pipeline		100%			37												120
Constitution Oil Pipeline		100%			67												80
Typhoon Oil Pipeline		100%			17												80
Tarantula Oil Pipeline		100%			4												30
Total miles					914
Offshore platforms:
Independence Hub (1)		80%							8,000				800			NA
Marco Polo		50%							4,300				150				60
Viosca Knoll 817		100%							671				145				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 VESCO Gathering System, 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 24%, 26% and 30% during the years ended December 31, 2007, 2006 and 2005, 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 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 eight pipeline junction and service platforms. This system also includes the 86-mile East Breaks System that connects the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25 to the HIOS pipeline system.

	§		The Viosca Knoll Gathering System transports natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas to several major interstate pipelines, including the Tennessee Gas, Columbia Gulf, Southern Natural, Transco, Dauphin Island Gathering System and Destin Pipelines.
	§		The Independence Trail natural gas pipeline transports natural gas from our Independence Hub platform to the Tennessee Gas Pipeline. Natural gas transported on the Independence Trail comes 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. In July 2007, the Independence Trail pipeline received first production from deepwater wells connected to the Independence Hub platform.
	§		The Green Canyon Laterals consist of 20 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 serves the Constitution and Ticonderoga fields located in the central Gulf of Mexico.
	§		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 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 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. (“Neptune”).
	§		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.
	§		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 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 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 19%, 18% and 17% during the years ended December 31, 2007, 2006 and 2005, respectively. These rates reflect the periods in which we owned an interest in such assets.

	§		The Cameron Highway Oil Pipeline 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 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 Constitution Oil Pipeline serves the Constitution and Ticonderoga fields located in the central Gulf of Mexico. The Constitution Oil Pipeline connects with our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System at a pipeline junction platform.

          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. For information regarding this project, see “Liquidity and Capital Resources — Capital Spending” included under Item 7 of this annual report.

          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, Independence Hub platform and East Cameron 373.

          On a weighted-average basis, utilization rates with respect to natural gas processing capacity of our offshore platforms were approximately 29%, 17% and 27% during the years ended December 31, 2007, 2006 and 2005, respectively. Likewise, utilization rates for our offshore platforms were approximately 26%, 19% and 9%, 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 fourteen pipeline junction and service platforms. Our pipeline junction and service platforms do not have processing capacity.

	§		The Independence Hub platform is located in Mississippi Canyon Block 920. This platform processes natural gas gathered from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. We successfully installed the Independence Hub platform and began earning demand revenues in March 2007. In July 2007, the Independence Hub platform received first production from deepwater wells connected to the platform. Currently, the platform is receiving approximately 900 MMcf/d of natural gas from fifteen wells.
	§		The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural gas from the Marco Polo, K2, K2 North and Genghis Khan fields. 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, L.L.C.

	§		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, which is located in the Mustang Island Block 103 area of the Gulf of Mexico, currently processes natural gas from the Falcon field.

     Petrochemical Services

          Our Petrochemical Services business segment includes five propylene fractionation facilities, an isomerization complex, and an octane additive production facility. This segment also includes approximately 683 miles of petrochemical pipeline systems.

          Propylene fractionation. Our propylene fractionation business consists primarily of five propylene fractionation facilities located in Texas and Louisiana, and approximately 613 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. The primary uses of isobutane are currently for the production of propylene oxide, isooctane and alkylate for motor gasoline. 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 methyl tertiary butyl ether (“MTBE”). 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 1, 2008, 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 (4 plants)

Texas

Various (1)

73

87

BRPC

Louisiana

30% (2)

7

23

Total capacity

80

110

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%

105

Lake Charles

Texas, Louisiana

50%

83

Others (6 systems) (5)

Texas

Various (6)

211

Total miles

683

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%, 86% and 83% during the years ended December 31, 2007, 2006 and 2005, 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, Enterprise Lou-Tex Propylene Pipeline L.P. (“Lou-Tex Propylene”) and Sabine Propylene Pipeline L.P. (“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 Duncan Energy Partners, see “Other Items - Initial Public Offering of Duncan Energy Partners” included under Item 7 of this annual report.

          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 105 MBPD, 97 MBPD and 64 MBPD during the years ended December 31, 2007, 2006 and 2005, respectively.

          Our octane additive facility currently has an isooctane production capacity of 12 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 58%, 58% and 29% during the years ended December 31, 2007, 2006 and 2005, 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. We believe 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, the 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 and Sabine Propylene pipelines are interstate common carrier pipelines 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 that provide services in interstate commerce 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 on a prospective basis only by the FERC, on its own initiative, or as a result of challenges to the rates by third parties if they are found unlawful. Unless the FERC grants specific authority to charge market-based 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 were appealed to the United States Court of Appeals for the District of Columbia (the “D.C. Circuit”). In May 2007, the D.C. Circuit issued an opinion in ExxonMobil Oil Corporation, et al. v. FERC, which denied the appeals and upheld the FERC’s tax allowance policy and the application of that policy in the individual pipeline proceeding. The FERC has issued additional orders reaffirming and clarifying its policy regarding the inclusion of an income tax allowance in rates. Most recently, the FERC issued an order in December 2007 which, among other things,

affirmed the FERC’s conclusion that the tax liability may be an actual or potential liability, further clarified its income tax allowance policy and concluded that the concept of a potential tax liability recognizes that tax liability may be deferred. However, the FERC left open the possibility that it could require different criteria before permitting an income tax allowance. Rehearing requests of the December 2007 order are pending at the FERC.

          The FERC’s authority over companies that provide natural gas pipeline transportation or storage services in interstate commerce also includes (i) certification, construction, and operation of certain new facilities; (ii) the acquisition, extension, disposition or abandonment of such facilities; (iii) the maintenance of accounts and records; (iv) the initiation, extension and termination of regulated 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 natural gas gathering pipelines and crude oil 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 limited regulation by the FERC under the NGPA as they 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.

     Sales of Natural Gas

          We are engaged in natural gas marketing activities. The resale of natural gas in interstate commerce made by intrastate pipelines or their affiliates is subject to FERC regulation unless the gas is produced by the pipeline carrier or an affiliate. Under current federal rules, however, the price at which we sell natural gas currently is not regulated, insofar as the interstate market is concerned and, for the most part, is not subject to state regulation. The FERC’s rules require pipelines and their marketing affiliates who sell natural gas in interstate commerce subject to the FERC’s jurisdiction to adhere to a code of conduct prohibiting market manipulation and transactions that have no legitimate business purpose or result in prices not reflective of legitimate forces of supply and demand. Those who violate this code of conduct may be subject to suspension or loss of authorization to perform such sales, disgorgement of unjust profits, or other appropriate non-monetary remedies imposed by the FERC. The FERC currently has a rulemaking pending which would implement revisions to these rules. The FERC is continually proposing and implementing new rules and regulations affecting segments of the natural gas industry. We cannot predict the ultimate impact of these regulatory changes on our natural gas marketing activities; however, we believe that any new regulations will also be applied to other natural gas marketers with whom we compete.

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 CWA imposes substantial civil and criminal penalties for non-compliance. The EPA has promulgated regulations that require us to have permits in order to discharge storm water runoff. The EPA has entered into agreements with states in which we operate whereby the permits are administered by the respective states.

          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 and some states are 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. In the past, although we utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and other materials may have been disposed of or released. In the future we may be required to remove or remediate these materials.

     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. Despite the “petroleum exclusion” of CERCLA that currently encompasses natural gas, we may nonetheless handle “hazardous substances” subject to CERCLA in the course of our operations and our pipeline systems may generate wastes that 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

          Like many publicly traded partnerships, we have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an administrative services agreement. As of December 31, 2007, there were approximately 3,200 EPCO personnel that spend all or a portion of their time engaged in our business. Approximately 1,900 of these individuals devote all

of their time performing management and operating duties for us. We reimburse EPCO for 100% of the costs it incurs to employ these individuals. The remaining approximate 1,300 personnel are part of EPCO’s shared service organization and spend all or a portion of their time engaged in our business. The cost for their services is reimbursed to EPCO and is generally based on the percentage of time such employees perform services on our behalf during the year. For additional information regarding the administrative services agreement and our relationship with EPCO, see Note 17 of the Notes to Consolidated Financial Statements included under Item 8 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, including us.

          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 (866) 230-0745 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.

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, demand and volumes of product for which we provide services. We may also incur credit and price risk to the extent counterparties do not perform in connection with our marketing of natural gas, NGLs and propylene.

          In the past, the price of natural gas has been extremely volatile, and we expect this volatility to continue. The NYMEX daily settlement price for natural gas for the prompt month contract in 2005 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. In 2007, the same index ranged from a high of $8.64 per MMBtu to a low of $5.38 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 and consumer product demand;
	§		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 domestic and international 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 currently transported, gathered or processed at our facilities originate from existing domestic and international resource basins, which naturally deplete over time. To offset this natural decline, our facilities will need access to production from newly discovered properties that are either being developed or expected to be 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.

          In addition, imported liquified natural gas (“LNG”), is expected to be a significant component of future natural gas supply to the United States. Much of this increase in LNG supplies is expected to be imported through new LNG facilities to be developed over the next decade. Twelve LNG projects have been approved by the FERC to be constructed in the Gulf Coast region and an additional two LNG projects

have been proposed for the region. We cannot predict which, if any, of these projects will be constructed. We may not realize expected increases in future natural gas supply available to our facilities and pipelines if (i) a significant number of these new projects fail to be developed with their announced capacity, (ii) there are significant delays in such development, (iii) they are built in locations where they are not connected to our assets or (iv) they do not influence sources of supply on our systems. If the expected increase in natural gas supply through imported LNG is not realized, projected natural gas throughput on our pipelines would decline, which could have a material adverse effect on our results of operations, cash flows and financial position.

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, 2007, we had approximately $6.90 billion of consolidated debt outstanding including Duncan Energy Partners, which 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 EPO’s 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 EPO’s Multi-Year Revolving Credit Facility, see Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

          EPO’s Multi-Year Revolving Credit Facility and each of its indentures for 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 EPO’s Multi-Year Revolving Credit Facility. In addition, under the terms of our junior subordinated notes, generally, if we elect to defer interest payments thereon, we are restricted from making distributions with respect to our equity securities. 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 EPO’s Multi-Year Revolving Credit Facility, to terminate all commitments to extend further credit. For additional information regarding EPO’s 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 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 we have expended or will expend significant capital, 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 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 ourselves or Duncan Energy Partners may 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, accretion 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 actual construction, development and acquisition costs could exceed forecasted amounts.

          We have significant expenditures for the development and construction of midstream 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 costs associated with our projects in the Rocky Mountains region increased over time 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.

We may not be able to consummate future public offerings of Duncan Energy Partners’ debt and equity securities 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 of partnership units in February 2007, there is no guarantee that, in the event of a proposed future contribution, Duncan Energy Partners will be able to complete future offerings of its securities in amounts that we would expect. If this occurs, we may 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 by the nationally recognized debt rating agencies. 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 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 EPCO 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, 2007, our balance sheet reflected $591.7 million of goodwill and $917.0 million of intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Generally accepted accounting principles in the United States (“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, 2007, we had approximately $6.90 billion of consolidated debt, of which approximately $5.03 billion was at fixed interest rates and approximately $1.87 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 and other key personnel. 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 certain 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 partner, 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.

          At any time, 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 ownership interest of a unitholder immediately prior to the issuance 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 EPGP.

          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 EPGP. 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 EPGP 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 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 EPGP, 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.

          EPGP 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 EPGP and its affiliates have duties to manage EPGP in a manner that is beneficial to its members. At the same time, EPGP has duties to manage our partnership in a manner that is beneficial to us. Therefore, EPGP’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 EPGP or EPCO to pursue a business strategy that favors us;
	§		decisions of EPGP 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 EPGP;
	§		under our partnership agreement, EPGP determines which costs incurred by it and its affiliates are reimbursable by us;
	§		EPGP is allowed to resolve any conflicts of interest involving us and EPGP and its affiliates;
	§		EPGP 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 EPGP 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 EPGP, including TEPPCO, may compete with us in certain circumstances;
	§		EPGP 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, EPGP 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 EPGP 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;
	§		EPGP intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us;
	§		EPGP controls the enforcement of obligations owed to us by our general partner and its affiliates; and
	§		EPGP 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, which could lower the trading price of our common units. 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 EPGP 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 EPGP or its officers or directors. EPGP 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 EPGP currently own approximately 34.0% of our outstanding common units, the removal of EPGP as our general partner is highly unlikely without the consent of both EPGP and its affiliates. As a result of this provision, 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.

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

          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 this provision, 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.

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

          If at any time EPGP and its affiliates own 85% or more of the common units then outstanding, EPGP 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.

Sales of a large number of our outstanding common units in the market may depress the market price of our common units.

          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, 2008, we had 435,241,826 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.

Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

          After June 30, 2008, our general partner, in accordance with our partnership agreement, may transfer its general partner interest without the consent of unitholders. In addition, our general partner may transfer its general partner interest to a third party in a merger or consolidation or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of Enterprise GP Holdings or its affiliates to transfer their equity interests in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to influence the decisions taken by the board of directors and officers of our general partner.

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 through 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, with respect to tax reports due on or after January 1, 2008, our operating subsidiaries are subject to the Revised Texas Franchise Tax on that portion of their revenue generated in Texas. Specifically, the Revised Texas Franchise Tax is 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 an entity-level tax upon us or our operating subsidiaries, the cash available for distribution to our common unitholders would be reduced.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

          The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, or Qualifying Income Exception, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. For

example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Section 7704(d) of the Internal Revenue Code. It is possible that these legislative efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us. Modifications to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. We are unable to predict whether any changes will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred.

          We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to successfully challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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 whether or not they 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 non-U.S. 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), other retirement plans and non-U.S. 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 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.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between EPGP and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

          When we issue additional common units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and EPGP. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and EPGP, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between EPGP and certain of our unitholders.

          A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns.

Item 1B. Unresolved Staff Comments.

          None.

Item 3. Legal Proceedings.

          On occasion, we or our unconsolidated affiliates are named as defendants in litigation relating to our normal business activities, including regulatory and environmental matters. Although we are insured against various business risks to the extent we believe it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify us against liabilities arising from future legal proceedings as a result of our ordinary business activities. We are unaware of any significant litigation, pending or threatened, that could have a significant adverse effect on our financial position, cash flows or results of operations. For detailed information regarding our legal proceedings, see Note 20 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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

          There were no matters voted on by our unitholders during the fourth quarter of 2007. On January 29, 2008, we held a special meeting where our unitholders where asked to approve the terms of the Enterprise Products 2008 Long-Term Incentive Plan (the “Enterprise Products 2008 LTIP”), which provides for awards of (i) options to purchase our common units, (ii) restricted units, (iii) phantom units, (iv) distribution equivalent rights and (v) common unit appreciation rights. These awards would be available for grant to employees and consultants of EPCO, including those who provide services on our behalf, and non-employee directors of our general partner. The Enterprise Products 2008 LTIP provides for the issuance of up to 10,000,000 of our common units as awards to such individuals. The following is a summary of the votes cast by our unitholders, which approved the terms of the Enterprise Products 2008 LTIP.

		Number of
		Votes Cast
For			243,283,982
Against			13,383,667
Abstentions			2,236,957

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, 2008, there were approximately 904 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
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
2007
1st Quarter		$	32.750			$	28.060			$	0.4750			Apr. 30, 2007				May 10, 2007
2nd Quarter		$	33.350			$	30.220			$	0.4825			Jul. 31, 2007				Aug. 9, 2007
3rd Quarter		$	33.700			$	26.136			$	0.4900			Oct. 31, 2007				Nov. 8, 2007
4th Quarter		$	32.450			$	29.920			$	0.5000			Jan. 31, 2008				Feb. 7, 2008

          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 2007.

Common Units Authorized for Issuance Under Equity Compensation Plan

          See “Securities Authorized for Issuance Under Equity Compensation Plans” under Item 12 of this annual report, which is incorporated by reference into this Item 5.

Issuer Purchases of Equity Securities

          We have not repurchased any of our common units since 2002. 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 1, 2008, 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,
		2007				2006				2005				2004				2003
Operating results data: (1)
Revenues		$	16,950,125			$	13,990,969			$	12,256,959			$	8,321,202			$	5,346,431
Income from continuing operations (2)		$	533,674			$	599,683			$	423,716			$	257,480			$	104,546
Income per unit from continuing operations:
Basic		$	0.96			$	1.22			$	0.92			$	0.83			$	0.42
Diluted		$	0.96			$	1.22			$	0.92			$	0.83			$	0.41
Other financial data:
Distributions per common unit (3)		$	1.9475			$	1.825			$	1.698			$	1.540			$	1.470

		As of December 31,
		2007				2006				2005				2004				2003
Financial position data: (1)
Total assets		$	16,608,007			$	13,989,718			$	12,591,016			$	11,315,461			$	4,802,814
Long-term and current maturities of debt (4)		$	6,906,145			$	5,295,590			$	4,833,781			$	4,281,236			$	2,139,548
Partners’ equity (5)		$	6,131,649			$	6,480,233			$	5,679,309			$	5,328,785			$	1,705,953
Total units outstanding (excluding treasury) (5)			435,297				432,408				389,861				364,786				217,780

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

For the years ended December 31, 2007, 2006 and 2005.

          The following information should be read in conjunction with our consolidated financial statements and our accompanying notes included under Item 8 of this annual report. Our discussion and analysis includes the following:

	§		Cautionary Note Regarding Forward-Looking Statements.
	§		Significant Relationships Referenced in this Discussion and Analysis.
	§		Overview of Business.
	§		Recent Developments – Discusses significant developments during the year ended December 31, 2007.
	§		Results of Operations – Discusses material year-to-year variances in our Statements of Consolidated Operations.
	§		Liquidity and Capital Resources – Addresses available sources of liquidity and capital resources and includes a discussion of our capital spending program.
	§		Critical Accounting Policies and Estimates.
	§		Other Items – Includes information related to contractual obligations, off-balance sheet arrangements, related party transactions, recent accounting pronouncements and similar disclosures.

          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
MMBbls		= million barrels
MMBtus		= million British thermal units
MMcf		= million cubic feet

          Our financial statements have been prepared in accordance with U.S generally accepted accounting principles (“GAAP”).

Cautionary Note Regarding Forward-Looking Statements

          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,” “seek,” “goal,” “forecast,” “intend,” “could,” “should,” “will,” “believe,” “may,” “potential” 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.

Significant Relationships Referenced in this Discussion and Analysis

          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.

          References to “EPO” mean Enterprise Products Operating LLC as successor in interest by merger to 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” mean Duncan Energy Partners L.P., which is a consolidated subsidiary of EPO. Duncan Energy Partners is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “DEP.” References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by EPO.

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

          References to “Enterprise GP Holdings” mean Enterprise GP Holdings L.P., a publicly traded affiliate, the units of which are listed on the NYSE under the ticker symbol “EPE.” Enterprise GP Holdings 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 affiliate, the common units of which are listed on the NYSE under the ticker symbol “TPP.” References to “TEPPCO GP” refer to Texas Eastern Products Pipeline Company, LLC, which is the general partner of TEPPCO and is wholly owned by Enterprise GP Holdings.

          References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include Energy Transfer Partners, L.P. (“ETP”). Energy Transfer Equity is a publicly traded Delaware limited partnership, the common units of which are listed on the NYSE under the ticker symbol “ETE.” The general partner of Energy Transfer Equity is LE GP, LLC (“LE GP”). On May 7, 2007, Enterprise GP Holdings acquired non-controlling interests in both LE GP and Energy Transfer Equity.

          References to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”) and EPE Unit III, L.P. (“EPE Unit III”), collectively, which are private company affiliates of EPCO, Inc. See Note 25 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding the formation of Enterprise Unit L.P. in February 2008.

          References to “EPCO” mean EPCO, Inc. and its wholly-owned private company affiliates, which are related party affiliates to all of the foregoing named entities.

          We, EPO, Duncan Energy Partners, DEP GP, EPGP, Enterprise GP Holdings, EPE Holdings, TEPPCO and TEPPCO GP are affiliates under the common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.

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 EPO. We are owned 98% by our limited partners and 2% by our general partner, EPGP. EPGP is owned 100% by Enterprise GP Holdings, a publicly traded affiliate listed on the NYSE under the ticker symbol “EPE.” We, EPGP and Enterprise GP Holdings are affiliates and under the common control of Dan L. Duncan, the Chairman and 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, 2007 through the date of this filing.

Questar Pipeline and Enterprise Products Partners Enter Into Definitive Agreements to Construct New Rockies Natural Gas Pipeline Hub

          In February 2008, we entered into definitive agreements with Questar Pipeline Company (“Questar”) to develop a new natural gas pipeline hub in the Rockies. As proposed, the White River Hub would be a header system that will be owned equally by us and Questar. The facilities would connect our natural gas processing complex near Meeker, Colorado, with up to six interstate pipelines in the Piceance Basin area, including the Questar Pipeline.

Our Pioneer Cryogenic Natural Gas Processing Facility Commences Operations

          In February 2008, we commenced operations at our recently completed Pioneer cryogenic natural gas processing facility. Located near the Opal Hub in southwestern Wyoming, this new facility is designed to process up to 750 MMcf/d of natural gas and extract as much as 30 MBPD of NGLs. We intend to maintain the operational capability of our Pioneer silica gel natural gas processing plant, which is located adjacent to the Pioneer cryogenic plant, as a back-up to provide producers with additional assurance of our processing capability at the complex. NGLs extracted at our Pioneer complex are transported on our Mid-America Pipeline System and ultimately to our Hobbs and Mont Belvieu NGL fractionators.

We and the Jicarilla Apache Nation Announce Plans to Form Joint Venture involving our San Juan Natural Gas Gathering Assets

          In November 2007, we and the Jicarilla Apache Nation announced our plans for the formation of a joint venture to own and operate natural gas gathering assets located on or near Jicarilla Apache Nation reservation lands. The joint venture would own and operate gathering assets in northwest New Mexico that were previously 100% owned by us. In order to take effect, the agreements related to the joint venture must be approved by the U.S. Department of the Interior. The Jicarilla Apache Nation is a federally-recognized Indian tribe, whose Reservation was established in 1887 and now consists of approximately 880,000 acres of land located on the eastern edge of the San Juan Basin.

          Under the terms of the joint venture agreement, we would receive relatively equivalent value for our contributions of (i) 545 miles of gathering lines, which have an approximate throughput of 31 MMcf/d, (ii) related gathering assets and (iii) 40 MMcf/d of redelivery and natural gas processing capacity through our San Juan Gathering System. The Jicarilla Apache Nation would contribute rights for access and use of reservation lands for operation and expansion of the joint venture gathering system, which will be operated

by us. The joint venture assets are currently part of our San Juan Gathering System, which is comprised of approximately 6,065 miles of natural gas pipelines in New Mexico and Colorado that gather more than 1 Bcf/d of natural gas.

EPO Increases and Extends its Multi-Year Revolving Credit Facility

          In November 2007, EPO amended its existing Multi-Year Revolving Credit Facility to, among other terms, increase total bank commitments from $1.25 billion to $1.75 billion and extend the maturity date to November 2012. In addition, the amendment provides us with the option to further increase commitments under the credit facility up to a maximum of $2.25 billion upon satisfaction of certain conditions. For additional information regarding this issuance of debt, see Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Our Meeker Natural Gas Processing Facility Commences Operations

          In October 2007, we commenced natural gas processing operations at our Meeker I facility, which recently completed its first phase of construction. Located in Colorado’s Piceance Basin, our Meeker I facility has a processing capacity of 750 MMcf/d of natural gas and is capable of extracting up to 35 MBPD of mixed NGLs. The Meeker II facility, which is under construction and expected to be completed in the third quarter of 2008, will double its processing capacity to 1.5 Bcf/d of natural gas and 70 MBPD of mixed NGLs.

          The two phases are supported by long-term commitments from producers, including EnCana and ExxonMobil. By the end of 2008, natural gas volumes processed at the facility are expected to exceed 800 MMcf/d, which we believe could yield to us approximately 40 MBPD of equity NGLs in full extraction mode. The Piceance Basin represents one of the most prolific and fastest growing energy producing areas in the nation, and the completion of our Meeker facility provides the region with valuable midstream infrastructure needed to accommodate those growing volumes.

Completion of the Final Phase of our Mid-America Pipeline Expansion Project

          In October 2007, we completed the expansion of the Rocky Mountain portion of our Mid-America Pipeline (“MAPL”) system. The final phase of this project consisted of installing new pumps and the modification of existing pumps, which increased system capacity by 20 MBPD. The first phase, which was completed in April 2007, provided an additional 30 MBPD of system capacity. Overall, these expansion projects increased the capacity of MAPL’s Rocky Mountain system from 225 MBPD to 275 MBPD. This expansion will accommodate expected mixed NGL volumes originating from our Meeker, Pioneer and Chaco facilities.

EPO Issues $800.0 Million of Senior Notes

          In September 2007, EPO sold $800.0 million in principal amount of 6.30% fixed-rate, unsecured senior notes due September 2017. Net proceeds from this offering were used to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility. In October 2007, EPO used borrowing capacity under its revolver to repay $500.0 million in principal amount due under its maturing Senior Notes E. For additional information regarding this issuance of debt, see Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Expansion of our Mont Belvieu Petrochemical Assets Completed

          In August 2007, we completed the expansion of our petrochemical assets in Mont Belvieu and southeast Texas. This expansion project included (i) the construction of a fourth propylene fractionator at our Mont Belvieu complex, which increased our propylene/propane fractionation capacity by approximately one billion pounds per year, or 15 MBPD, and (ii) the expansion of two refinery grade propylene pipelines which added 50 MBPD of capacity into Mont Belvieu.

Completion of our Hobbs NGL Fractionator

          In August 2007, we completed construction of our Hobbs NGL fractionator, which is designed to handle up to 75 MBPD of mixed NGLs. The new fractionator is strategically located at the interconnection of our MAPL and our Seminole pipelines near Hobbs, New Mexico. Our Hobbs NGL fractionator offers another key hub for separating mixed NGLs produced at our Meeker, Pioneer and Chaco facilities into purity NGL products.

Changes in our Management Team

          In July 2007, we announced changes to our senior management team that became effective August 1, 2007. The board of directors of our general partner elected Michael A. Creel president and chief executive officer, W. Randall Fowler executive vice president and chief financial officer, and William Ordemann executive vice president and chief operating officer. Mr. Creel replaces Robert G. Phillips who resigned effective June 30, 2007. Mr. Fowler was promoted to fill the position left vacant by Mr. Creel’s promotion. Mr. Ordemann was promoted to fill the position vacated by Dr. Ralph S. Cunningham, who is now the president and chief executive officer of Enterprise GP Holdings. Mr. Creel had previously held this position.

Our Independence Hub Platform and Trail Pipeline Receive First Production

          In July 2007, our Independence Hub platform and Independence Trail pipeline received first production from deepwater production wells connected to the Independence Hub platform. As a result, these assets began earning fee-based revenues for natural gas processing and transportation services. These amounts are in addition to the demand fee revenues that Independence Hub began earning in March 2007. Currently, the platform is receiving approximately 900 MMcf/d of natural gas from fifteen wells.

We and TEPPCO Complete the First Portion of the Jonah Phase V Expansion Project

          In July 2007, we completed the first portion of the Phase V Expansion of the Jonah Gathering System, which increased the system gathering capacity to 2.0 Bcf/d. The second and final phase of the expansion, which is targeted for completion in April 2008, is expected to increase the system’s gathering capacity further to 2.4 Bcf/d.

Expansion of our Houston Ship Channel NGL Import and Export Terminal Completed

          In June 2007, we announced the completion of our project to expand the capabilities of our import/export terminal at the Houston Ship Channel to handle incremental volumes of natural gas liquids and liquefied petroleum gases.

EPO Issues $700.0 Million of Junior Notes

          In May 2007, EPO sold $700 million in principal amount of fixed/floating unsecured junior subordinated notes due January 2068. Net proceeds from this offering were used by EPO to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. For additional information regarding this issuance of debt, see Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Creation of our Natural Gas Services and Marketing Business

          In March 2007, we announced the expansion of our natural gas services and marketing business similar to our existing NGL and petrochemical marketing businesses. This business will include all of our existing natural gas supply and marketing activities, which currently include producer wellhead services, facility fuel procurement, pipeline and storage capacity optimization and a full range of market customer delivery arrangements. This initiative is expected to broaden our role in the natural gas markets by linking

our extensive U.S. natural gas pipeline and storage assets, thus providing customers with value-added solutions and reducing our operating costs through enhanced fuel procurement practices.

Duncan Energy Partners Completes its Initial Public Offering

          In February 2007, a consolidated subsidiary of ours, Duncan Energy Partners, completed its underwritten initial public offering of 14,950,000 common units. Duncan Energy Partners, a Delaware limited partnership, was formed by EPO to acquire ownership interests in certain of our midstream energy businesses. EPO owns the 2% general partner interest and 5,351,571 common units of Duncan Energy Partners as well as a direct 34% equity interest in each of Duncan Energy Partners operating subsidiaries. For additional information regarding Duncan Energy Partners, see “Other Items – Initial Public Offering of Duncan Energy Partners” included within this Item 7.

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 technologies 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 segment gross operating margin as consolidated operating income before (i) 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 costs. Gross operating margin is exclusive of other income and expense transactions, provision for income taxes, minority interest, extraordinary charges and the cumulative effect of change in accounting principle. 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.

          Our consolidated gross operating margin amounts include the gross operating margin amounts of Duncan Energy Partners on a 100% basis. Volumetric data associated with the operations of Duncan Energy Partners are also included on a 100% basis in our consolidated statistical data.

          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	)
2005 Averages		$	8.64			$	56.47			$	0.62			$	0.91			$	1.09			$	1.15			$	1.26			$	0.42			$	0.37
2006 Averages		$	7.24			$	66.09			$	0.66			$	1.01			$	1.20			$	1.24			$	1.44			$	0.47			$	0.41
2007
1st Quarter		$	6.77			$	58.02			$	0.59			$	0.97			$	1.13			$	1.22			$	1.37			$	0.45			$	0.40
2nd Quarter		$	7.55			$	64.97			$	0.72			$	1.13			$	1.33			$	1.45			$	1.65			$	0.51			$	0.46
3rd Quarter		$	6.16			$	75.48			$	0.82			$	1.23			$	1.44			$	1.49			$	1.68			$	0.52			$	0.46
4th Quarter		$	6.97			$	90.75			$	1.04			$	1.51			$	1.79			$	1.80			$	2.01			$	0.59			$	0.54
2007 Averages		$	6.86			$	72.30			$	0.79			$	1.21			$	1.42			$	1.49			$	1.68			$	0.52			$	0.47

 

          The following table presents our significant average throughput, production and processing volumetric data. These statistics are reported on a net basis, taking into account our ownership interests in certain joint ventures and reflect the periods in which we owned an interest in such operations. These statistics include volumes for newly constructed assets since the dates such assets were placed into service and for recently purchased assets since the date of acquisition.

		For the Year Ended December 31,
		2007				2006				2005
NGL Pipelines & Services, net:
NGL transportation volumes (MBPD)			1,666				1,577				1,478
NGL fractionation volumes (MBPD)			394				312				292
Equity NGL production (MBPD) (1)			88				63				68
Fee-based natural gas processing (MMcf/d)			2,565				2,218				1,767
Onshore Natural Gas Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)			6,632				6,012				5,916
Offshore Pipelines & Services, net:
Natural gas transportation volumes (BBtus/d)			1,641				1,520				1,780
Crude oil transportation volumes (MBPD)			163				153				127
Platform gas processing (MMcf/d)			494				159				252
Platform oil processing (MBPD)			24				15				7
Petrochemical Services, net:
Butane isomerization volumes (MBPD)			90				81				81
Propylene fractionation volumes (MBPD)			68				56				55
Octane additive production volumes (MBPD)			9				9				6
Petrochemical transportation volumes (MBPD)			105				97				64
Total, net:
NGL, crude oil and petrochemical transportation volumes (MBPD)			1,934				1,827				1,669
Natural gas transportation volumes (BBtus/d)			8,273				7,532				7,696
Equivalent transportation volumes (MBPD) (2)			4,111				3,809				3,694

 

Comparison of Results of Operations

          The following table summarizes the key components of our results of operations for the periods indicated (dollars in thousands):

		For the Year Ended December 31,
		2007				2006				2005
Revenues		$	16,950,125			$	13,990,969			$	12,256,959
Operating costs and expenses			16,009,051				13,089,091				11,546,225
General and administrative costs			87,695				63,391				62,266
Equity in income of unconsolidated affiliates			29,658				21,565				14,548
Operating income			883,037				860,052				663,016
Interest expense			311,764				238,023				230,549
Provision for income taxes			15,257				21,323				8,362
Minority interest			30,643				9,079				5,760
Net income			533,674				601,155				419,508

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

		For the Year Ended December 31,
		2007				2006				2005
Gross operating margin by segment:
NGL Pipelines & Services		$	812,521			$	752,548			$	579,706
Onshore Natural Gas Pipelines & Services			335,683				333,399				353,076
Offshore Pipeline & Services			171,551				103,407				77,505
Petrochemical Services			172,313				173,095				126,060
Total segment gross operating margin		$	1,492,068			$	1,362,449			$	1,136,347