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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
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from       to      .
 
Commission file number: 1-14323
ENTERPRISE PRODUCTS PARTNERS L.P.
(Exact name of Registrant as Specified in Its Charter)
     
Delaware   76-0568219
(State or Other Jurisdiction of   (I.R.S. Employer Identification No.)
Incorporation or Organization)    
     
1100 Louisiana, 10th Floor, Houston, Texas
(Address of Principal Executive Offices)
  77002
(Zip Code)
(713) 381-6500
(Registrant’s Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
     
Title of Each Class   Name of Each Exchange On Which Registered
     
Common Units   New York Stock Exchange
Securities to be registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, 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        
  Business and Properties.     2  
Item 1A.
  Risk Factors.     30  
  Unresolved Staff Comments.     49  
  Legal Proceedings.     49  
  Submission of Matters to a Vote of Security Holders.     49  
 
  PART II        
 
           
  Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.     50  
  Selected Financial Data.     51  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations.     52  
  Quantitative and Qualitative Disclosures About Market Risk.     84  
  Financial Statements and Supplementary Data.     89  
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.     171  
  Controls and Procedures.     171  
  Other Information.     175  
 
           
 
  PART III        
  Directors, Executive Officers and Corporate Governance.     175  
  Executive Compensation.     181  
  Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.     190  
  Certain Relationships and Related Transactions, and Director Independence.     194  
  Principal Accountant Fees and Services.     203  
 
           
 
  PART IV        
  Exhibits and Financial Statement Schedules.     204  
        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

 


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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.

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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, 10th 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.

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          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.

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          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.

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          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

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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.

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          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.

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          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  
             
 
(1)   The approximate net natural gas processing capacity does not necessarily correspond to our ownership interest in each facility. It is based on a variety of factors such as volumes processed at the facility and ownership interest in the facility.
 
(2)   We acquired a silica gel natural gas processing facility from TEPPCO in March 2006 and subsequently increased the processing capacity from 0.3 Bcf/d to 0.6 Bcf/d. In addition, we constructed a new cryogenic processing facility having 0.75 Bcf/d of processing capacity, which became operational in February 2008.
 
(3)   In October 2007, we commenced natural gas processing operations at our Meeker facility. Phase II of the Meeker facility, which is under construction and expected to be completed in the third quarter of 2008, will double the natural gas processing capacity to 1.5 Bcf/d at this facility.
 
(4)   Includes our Venice, Blue Water, Sea Robin and Burns Point facilities located in Louisiana; Indian Basin and Carlsbad facilities located in New Mexico; and San Martin, Delmita, Sonora, Shilling and Indian Springs facilities located in Texas. We acquired the Indians Springs facility in January 2005. Our ownership in the Venice plant is through our 13.1% equity method investment in Venice Energy Services Company, L.L.C. (“VESCO”).
 
(5)   Our ownership in these facilities ranges from 7.4% to 100%.
          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.

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          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  
 
                       
 
(1)   We hold a 74.2% interest in this system through a majority owned subsidiary, Dixie Pipeline Company (“Dixie”).
 
(2)   We hold a 90% interest in this system through a majority owned subsidiary, Seminole Pipeline Company (“Seminole”).
 
(3)   Of the 612 total miles for this system, we own 100% of 559 miles and 43.5% of the remaining 53 miles.
 
(4)   Reflects consolidated ownership of this system by EPO (34%) and Duncan Energy Partners (66%).
 
(5)   Includes our Tri-States, Belle Rose, Wilprise, and Chunchula pipelines located in the coastal regions of Alabama, Louisiana, and Mississippi and our Meeker pipeline in Colorado. We completed the Meeker pipeline in 2007, which transports NGLs from our Meeker natural gas processing facility to the Mid-America Pipeline System.
 
(6)   The amount shown for Texas includes 33 underground caverns with an aggregate useable storage capacity of approximately 100 MMBbls that we own jointly with Duncan Energy Partners. These caverns are located in Mont Belvieu, Texas.
 
(7)   The 154.9 MMBbls of total useable storage capacity includes 20.8 MMBbls held under operating leases. The leased facilities are located in Texas, Louisiana and Kansas.
          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

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      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.

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      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  
             
 
(1)   The approximate net NGL fractionation capacity does not necessarily correspond to our ownership interest in each facility. It is based on a variety of factors such as volumes processed at the facility and ownership interest in the facility.
          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.

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  §   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.

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          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

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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  
 
                               
 
(1)   We own a 50% undivided interest in the 641-mile Channel pipeline system, which is a component of the Texas Intrastate System. The remaining 50% is owned by affiliates of Energy Transfer Equity. In addition, we own less than a 100% undivided interest in certain segments of the Enterprise Texas pipeline system.
 
(2)   Reflects consolidated ownership of Acadian Gas by EPO (34%) and Duncan Energy Partners (66%). Also includes the 49.5% equity investment that Acadian Gas has in the Evangeline pipeline.
 
(3)   Includes the Delmita, Big Thicket, Indian Springs and Canales gathering systems located in Texas and the Petal and Hattiesburg pipelines located in Mississippi. The Delmita and Big Thicket gathering systems are integral parts of our natural gas processing operations, the results of operations and assets of which are accounted for under our NGL Pipelines & Services business segment. We acquired the Canales gathering system in connection with the Encinal acquisition in July 2006. The Petal and Hattiesburg pipelines are integral components of our natural gas storage operations.
 
(4)   We own 100% of these assets with the exception of the Indian Springs system, in which we own an 80% undivided interest through a consolidated subsidiary.
 
(5)   This facility is held under an operating lease that expires in January 2028.
 
(6)   We hold this facility under an operating lease that expires in December 2012.
          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.

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          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

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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-

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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.

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          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  
 
(1)   In July 2007, the Independence Hub platform and Independence Trail pipeline received first production from deepwater production wells connected to the Independence Hub platform. The Independence Hub platform began earning demand revenues in March 2007.
 
(2)   Our ownership interests in the Green Canyon Laterals ranges from 0% to 100%.
 
(3)   Data shown for the Anaconda Gathering System includes the 30-mile Constitution natural gas pipeline, which we constructed and placed into service in 2006. The Constitution natural gas pipeline has a net capacity of approximately 200 MMcf/d.
          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.

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  §   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.

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          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

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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

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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.

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          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          
 
(1)   We own a 54.6% interest and lease the remaining 45.4% of a facility having 17 MBPD of plant capacity. We own a 66.7% interest in a second facility having 41 MBPD of total plant capacity. We own 100% of the remaining two facilities, which have 14 MBPD and 15 MBPD of plant capacity, respectively.
 
(2)   Our ownership interest in this facility is held indirectly through our equity method investment in Baton Rouge Propylene Concentrator LLC (“BRPC”).
 
(3)   On a weighted-average basis, utilization rates for this facility were approximately 78%, 70% and 70% during 2007, 2006 and 2005, respectively.
 
(4)   Reflects consolidated ownership of these pipelines by EPO (34%) and Duncan Energy Partners (66%).
 
(5)   Includes our Texas City PGP Delivery System and Port Neches, Bay Area, La Porte, Port Arthur and Bayport petrochemical pipelines.
 
(6)   We own 100% of these pipelines with the exception of the 17-mile La Porte pipeline, in which we hold an aggregate 50% indirect interest through our equity method investments in La Porte Pipeline Company L.P. and La Porte Pipeline GP, L.L.C.
          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

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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

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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,

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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.

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          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

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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

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(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

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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.

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          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

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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.

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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

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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.

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          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

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  §   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.

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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

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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

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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

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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.

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          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.

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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

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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

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      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.

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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

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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

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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

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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.

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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  

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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.

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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  
 
(1)   In general, our historical operating results and financial position have been affected by numerous acquisitions since 2002. Our most significant transaction to date was the GulfTerra Merger, which was completed on September 30, 2004. The aggregate value of the total consideration we paid or issued to complete the GulfTerra Merger was approximately $4 billion. We accounted for the GulfTerra Merger and our other acquisitions using purchase accounting; therefore, the operating results of these acquired entities are included in our financial results prospectively from their respective acquisition dates.
 
(2)   Amounts presented for the years ended December 31, 2006, 2005 and 2004 are before the cumulative effect of accounting changes.
 
(3)   Distributions per common unit represent declared cash distributions with respect to the four fiscal quarters of each period presented.
 
(4)   In general, the balances of our long-term and current maturities of debt have increased over time as a result of financing all or a portion of acquisitions and other capital spending.
 
(5)   We regularly issue common units through underwritten public offerings and, less frequently, in connection with acquisitions or other transactions. The increase in partners’ equity since 2003 has been the result of such transactions, with the September 2004 issuance of 104.5 million common units in connection with the GulfTerra Merger being our largest. For additional information regarding our partners’ equity and unit history, see Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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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

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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

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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

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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.

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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

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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.

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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  
     
 
(1)   Natural gas, NGL, polymer grade propylene and refinery grade propylene prices represent an average of various commercial index prices including Oil Price Information Service (“OPIS”) and Chemical Market Associates, Inc. (“CMAI”). Natural gas price is representative of Henry-Hub I-FERC. NGL prices are representative of Mont Belvieu Non-TET pricing. Polymer-grade propylene represents average CMAI contract pricing. Refinery grade propylene represents an average of CMAI spot prices.
 
(2)   Crude oil price is representative of an index price for West Texas Intermediate.
          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  
   
                       
 
(1)   Volumes for 2005 have been revised to incorporate asset-level definitions of equity NGL production volumes.
 
(2)   Reflects equivalent energy volumes where 3.8 MMBtus of natural gas are equivalent to one barrel of NGLs.

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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  
     
          For a reconciliation of non-GAAP gross operating margin to GAAP operating income and further to GAAP income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles, see “Other Items — Non-GAAP reconciliations” included within this Item 7.
          The following table summarizes the contribution to consolidated revenues from the sale of NGL, natural gas and petrochemical products during the periods indicated (dollars in thousands):
                         
    For the Year Ended December 31,
    2007   2006   2005
     
NGL Pipelines & Services:
                       
Sale of NGL products
  $ 11,822,291     $ 9,496,926     $ 8,176,370  
Percent of consolidated revenues
    70 %     68 %     67 %
Onshore Natural Gas Pipelines & Services:
                       
Sale of natural gas
  $ 1,633,214     $ 1,228,916     $ 1,065,542  
Percent of consolidated revenues
    10 %     9 %     9 %
Petrochemical Services:
                       
Sale of petrochemical products
  $ 1,796,251     $ 1,545,693     $ 1,311,956  
Percent of consolidated revenues
    11 %     11 %     11 %
Comparison of 2007 with 2006
          Revenues for 2007 were $16.95 billion compared to $13.99 billion for 2006. The increase in consolidated revenues year-to-year is primarily due to higher sales volumes and energy commodity prices in 2007 relative to 2006. These factors accounted for a $2.98 billion increase in consolidated revenues associated with our marketing activities. Revenues from business interruption insurance proceeds totaled $36.1 million in 2007 compared to $63.9 million in 2006.
          Operating costs and expenses were $16.01 billion for 2007 versus $13.09 billion for 2006. The year-to-year increase in consolidated operating costs and expenses is primarily due to an increase in the

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cost of sales associated with our marketing activities. The cost of sales of our NGL, natural gas and petrochemical products increased $2.46 billion year-to-year as a result of an increase in volumes and higher energy commodity prices. Operating costs and expenses associated with our natural gas processing plants increased $185.7 million year-to-year as a result of higher energy commodity prices in 2007 relative to 2006. Operating costs and expenses associated with assets we constructed and placed into service or acquired since January 1, 2006 increased $188.1 million year-to-year.
          General and administrative costs were $87.7 million for 2007 compared to $63.4 million for 2006. The $24.3 million year-to-year increase in general and administrative costs is primarily due to the recognition of a severance obligation during 2007 and an increase in legal fees.
          Changes in our revenues and costs and expenses year-to-year are explained in part by changes in energy commodity prices. The weighted-average indicative market price for NGLs was $1.19 per gallon during 2007 versus $1.00 per gallon during 2006, a year-to-year increase of 19%. Our determination of the weighted-average indicative market price for NGLs is based on U.S. Gulf Coast prices for such products at Mont Belvieu, which is the primary industry hub for domestic NGL production. The market price of natural gas (as measured at Henry Hub) averaged $6.86 per MMBtu during 2007 versus $7.24 per MMBtu during 2006. For additional historical energy commodity pricing information, see the table on page 58.
          Equity earnings from unconsolidated affiliates were $29.7 million for 2007 compared to $21.6 million for 2006. Equity earnings from our investment in Jonah increased $9.1 million year-to-year. Equity earnings for 2007 include a non-cash impairment charge of $7.0 million associated with our investment in Nemo compared to a non-cash impairment charge of $7.4 million in 2006 related to our investment in Neptune. Collectively, equity earnings from our other unconsolidated affiliates decreased $1.4 million year-to-year primarily due to the sale of our investment in Coyote Gas Treating, LLC in August 2006.
          Operating income for 2007 was $883.0 million compared to $860.1 million for 2006. Collectively, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to the $22.9 million increase in operating income year-to-year.
          Interest expense increased $73.7 million year-to-year primarily due to our issuance of junior subordinated notes in the second quarter of 2007 and third quarter of 2006 and the issuance of Senior Notes L in the third quarter of 2007. Our consolidated interest expense for 2007 includes $11.6 million associated with Duncan Energy Partners’ credit facility. Our average debt principal outstanding was $6.26 billion in 2007 compared to $4.93 billion in 2006. Minority interest increased $21.6 million year-to-year attributable to the public unit holders of Duncan Energy Partners and third-party ownership interests in the Independence Hub platform.
          As a result of items noted in the previous paragraphs, our consolidated net income decreased $67.5 million year-to-year to $533.7 million in 2007 compared to $601.2 million in 2006. Net income for 2006 includes a $1.5 million benefit relating to the cumulative effect of change in accounting principle. For additional information regarding the cumulative effect of change in accounting principle we recorded in 2006, see Note 8 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
          The following information highlights significant year-to-year variances in gross operating margin by business segment:
          NGL Pipelines & Services. Gross operating margin from this business segment was $812.5 million for 2007 compared to $752.5 million for 2006. Gross operating margin for 2007 includes $32.7 million of proceeds from business interruption insurance claims compared to $40.4 million of proceeds during 2006. Strong demand for NGLs in 2007 compared to 2006 led to higher natural gas processing margins, increased volumes of natural gas processed under fee-based contracts and higher NGL throughput volumes at certain of our pipelines and fractionation facilities. The following paragraphs provide a discussion of segment results excluding proceeds from business interruption insurance claims.

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          Gross operating margin from NGL pipelines and storage was $302.2 million for 2007 compared to $265.7 million for 2006. Total NGL transportation volumes increased to 1,666 MBPD during 2007 from 1,577 MBPD during 2006. The $36.5 million year-to-year increase in gross operating margin is primarily due to higher pipeline transportation and NGL storage volumes at certain of our facilities and higher transportation fees charged to shippers on our Mid-America Pipeline System. Our DEP South Texas NGL Pipeline contributed $21.1 million of gross operating margin and 73 MBPD of NGL transportation volumes during 2007. The increase in gross operating margin year-to-year was partially offset by lower volumes and higher costs resulting from the November 2007 rupture of the Dixie Pipeline and a one-time benefit in 2006 for the settlement of a pipeline contamination incident.
          Gross operating margin from our natural gas processing and related NGL marketing business was $389.1 million for 2007 compared to $359.7 million for 2006. The $29.4 million increase in gross operating margin year-to-year is largely due to improved results from our south Texas, Louisiana and Chaco natural gas processing facilities attributable to higher volumes and equity NGL sales revenues. Fee-based processing volumes increased to 2.6 Bcf/d during 2007 from 2.2 Bcf/d during 2006. Equity NGL production increased to 88 MBPD during 2007 from 63 MBPD during 2006. The year-to-year increase in gross operating margin from this business was partially offset by expenses associated with start-up delays at our Meeker and Pioneer natural gas processing plants.
          The start-up delays at both our Meeker and Pioneer facilities are attributable to the replacement of defective high pressure valves and the need to address third-party engineering design problems. We are actively engaged in efforts to obtain recovery for certain of our losses. During 2007, we entered into transactions to economically hedge a percentage of the expected NGL production at these facilities, which entailed the physical forward sale of NGLs and the purchase of natural gas. As a result of the unexpected downtime at our Meeker facility and the delayed start-up of our Pioneer facility, the actual NGL production and natural gas consumption during the fourth quarter of 2007 was less than the volume we hedged. The cost to replace the defective valves and the expense resulting from a non-cash, mark-to-market charge on the short, or over hedged, NGL balance and the liquidation of the long natural gas position totaled $30.0 million during 2007. Gross operating margin generated by our Meeker facility from actual production was offset by a decrease in gross operating margin from our NGL marketing business.
          Gross operating margin from NGL fractionation was $88.4 million for 2007 compared to $86.8 million for 2006. Fractionation volumes increased from 312 MBPD during 2006 to 394 MBPD during 2007. The year-to-year increase in gross operating margin of $1.6 million is primarily due to higher volumes at our Norco NGL fractionator during 2007 relative to 2006. Our Norco NGL fractionator returned to normal operating rates in the second quarter of 2006 after suffering a reduction of fractionation volumes due to the effects of Hurricane Katrina. Gross operating margin attributable to our Hobbs NGL fractionator, which became operational in August 2007, was largely offset by start-up expenses. Fractionation volumes for 2007 include 36 MBPD from our Hobbs fractionator.
          Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment was $335.7 million for 2007 compared to $333.4 million for 2006. Our total onshore natural gas transportation volumes were 6,632 BBtu/d for 2007 compared to 6,012 BBtu/d for 2006. Gross operating margin from our onshore natural gas pipeline business was $307.2 million for 2007 compared to $312.3 million for 2006. The $5.1 million year-to-year decrease in gross operating margin from this business is largely due to higher operating costs on our Acadian Gas System, Waha and Carlsbad Gathering Systems and our Texas Intrastate System.
          Results from our onshore natural gas pipeline business for 2007 include $5.5 million of gross operating margin from our Piceance Creek Gathering System, which we acquired in December 2006. Equity earnings from our investment in Jonah increased $9.1 million year-to-year. The Piceance Creek Gathering System and our net share of the gathering volumes on the Jonah Gathering System contributed 789 BBtu/d, collectively, of natural gas gathering volumes during 2007.
          Gross operating margin from our natural gas storage business was $28.4 million for 2007 compared to $21.1 million for 2006. The $7.3 million year-to-year increase in gross operating margin is

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largely due to improved results from our Wilson natural gas storage facility attributable to lower repair costs in 2007 relative to 2006 and a 2006 loss on the sale of cushion gas. All repairs are now complete on the three storage wells at our Wilson facility that were taken out of service in the second quarter of 2006. We are in the process of dewatering the caverns and returning working gas storage capacity to service, which should be largely complete in the second quarter of 2008. Gross operating margin from our Petal facility includes an $8.4 million benefit in 2006 for a well measurement gain.
          Offshore Pipelines & Services. Gross operating margin from this business segment was $171.6 million for 2007 compared to $103.4 million for 2006, a year-to-year increase of $68.2 million. Our Independence project contributed $85.0 million of gross operating margin during 2007 on average natural gas throughput of 423 BBtus/d. Segment gross operating margin for 2007 includes $3.4 million of proceeds from business interruption insurance claims compared to $23.5 million of proceeds in 2006. The following paragraphs provide a discussion of segment results excluding proceeds from business interruption insurance claims.
          Gross operating margin from our offshore platform services business was $111.7 million for 2007 compared to $34.6 million for 2006. The $77.1 million year-to-year increase in gross operating margin is primarily due to our start up of the Independence Hub Platform in 2007, which contributed $63.6 million of gross operating margin in 2007. In addition, gross operating margin from this business increased $13.5 million year-to-year primarily due to higher volumes during 2007 versus 2006. Our net platform natural gas processing volumes increased to 494 MMcf/d in 2007 from 159 MMcf/d in 2006.
          Gross operating margin from our offshore natural gas pipeline business was $35.4 million for 2007 compared to $22.4 million for 2006. Offshore natural gas transportation volumes were 1,641 BBtu/d during 2007 versus 1,520 BBtu/d during 2006. Our Independence Trail Pipeline reported $21.4 million of gross operating margin and 423 BBtus/d of transportation volumes for 2007. Results from our Independence Trail Pipeline were partially offset by a decrease in volumes and revenues from our Viosca Knoll Gathering System and Constitution Gas Pipeline. Gross operating margin for 2007 includes a non-cash impairment charge of $7.0 million associated with our investment in Nemo compared to charge of $7.4 million in 2006 related to our investment in Neptune.
          Gross operating margin from our offshore crude oil pipeline business was $21.1 million for 2007 versus $23.0 million for 2006. The $1.9 million year-to-year decrease in gross operating margin is primarily due to lower transportation volumes on our certain of our offshore crude oil pipelines and higher operating costs on our Poseidon Oil Pipeline System during 2007 relative to 2006. An increase in revenues year-to-year on our Cameron Highway Oil Pipeline System attributable to higher volumes was more than offset by a one-time expense of $8.8 million associated with the early termination of Cameron Highway’s credit facility. Crude oil transportation volumes on our Cameron Highway Oil Pipeline System net to our ownership interest were 44 MBPD during 2007 compared to 32 MBPD during 2006. Total offshore crude oil transportation volumes were 163 MBPD during 2007 versus 153 MBPD during 2006.
          BP P.L.C. announced in December 2007 that crude oil and natural gas production from its Atlantis Development had commenced. Crude oil volumes from this development are transported on our Cameron Highway Oil Pipeline System. Natural gas production from the Atlantis development is transported on our Manta Ray Gathering System and Nautilus Pipeline and processed at our Neptune facility. Recovered NGLs are fractionated at our Promix fractionator.
           Petrochemical Services. Gross operating margin from this business segment was $172.3 million for 2007 compared to $173.1 million for 2006. Gross operating margin from our butane isomerization business was $91.4 million for 2007 compared to $73.2 million for 2006. The $18.2 million year-to-year increase in gross operating margin is attributable to higher processing volumes and by-products sales revenues. Butane isomerization volumes were 90 MBPD for 2007 compared to 81 MBPD for 2006.
          Gross operating margin from our propylene fractionation and pipeline activities was $62.6 million for 2007 versus $63.4 million for 2006. The $0.8 million year-to-year decrease in gross operating margin is primarily attributable to higher operating costs and expenses attributable to our propylene pipelines and

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our propylene storage and export facility. Petrochemical transportation volumes were 105 MBPD during 2007 compared to 97 MBPD during 2006. Gross operating margin from octane enhancement was $18.3 million for 2007 compared to $36.6 million for 2006. The year-to-year decrease of $18.3 million is primarily due to lower sales margins in 2007 relative to 2006. Octane enhancement production was 9 MBPD during 2007 and 2006.
     Comparison of 2006 with 2005
          Revenues for 2006 were $13.99 billion compared to $12.26 billion for 2005. The increase in consolidated revenues year-to-year is primarily due to higher sales volumes and energy commodity prices in 2006 relative to 2005. These factors accounted for a $1.72 billion increase in consolidated revenues associated with our marketing activities. Revenues for 2006 include $63.9 million of proceeds from business interruption insurance claims compared to $4.8 million of proceeds for 2005.
          Operating costs and expenses were $13.09 billion for 2006 versus $11.55 billion for 2005. The year-to-year increase in consolidated operating costs and expenses is primarily due to an increase in the cost of sales associated with our marketing activities. The cost of sales of our NGL and petrochemical products increased $1.21 billion year-to-year as a result of an increase in volumes and higher energy commodity prices. Operating costs and expenses associated with our natural gas processing plants increased $258.7 million as a result of higher energy commodity prices in 2006 relative to 2005. General and administrative costs increased $1.1 million year-to-year primarily due to higher costs associated with FERC rate case filings for our Mid-America Pipeline System and Texas Intrastate System.
          Changes in our revenues and costs and expenses year-to-year are explained in part by changes in energy commodity prices. The weighted-average indicative market price for NGLs was $1.00 per gallon during 2006 versus $0.91 per gallon during 2005, a year-to-year increase of 10%. The Henry Hub market price of natural gas averaged $7.24 per MMBtu during 2006 versus $8.64 per MMBtu during 2005. Polymer grade and refinery grade propylene index prices increased 12% year-to-year.
          Equity earnings from unconsolidated affiliates were $21.6 million for 2006 compared to $14.5 million for 2005. An increase in volumes from offshore production led to a collective $11.8 million increase year-to-year in equity earnings from Poseidon and Deepwater Gateway. Equity earnings from Cameron Highway increased $4.9 million year-to-year. Our equity earnings for 2005 included an $11.5 million charge associated with the refinancing of Cameron Highway’s project finance debt. Also, equity earnings from our investment in Neptune decreased $10.3 million year-to-year primarily due to a $7.4 million non-cash impairment charged recorded in 2006 associated with this investment.
          Operating income for 2006 was $860.1 million compared to $663.0 million for 2005. Collectively, the aforementioned changes in revenues, costs and expenses and equity earnings contributed to the $197.1 million increase in operating income year-to-year.
          Interest expense increased $7.5 million year-to-year primarily due to our issuance of junior notes in 2006 and an increase in interest rates charged on our variable rate debt. Our average debt principal outstanding was $4.93 billion in 2006 compared to $4.63 billion in 2005.
          As a result of items noted in the previous paragraphs, our consolidated net income increased $181.6 million year-to-year to $601.2 million in 2006 compared to $419.5 million in 2005. Net income for both years includes the recognition of non-cash amounts related to the cumulative effect of changes in accounting principles. We recorded a $1.5 million benefit in 2006 and a $4.2 million charge in 2005 related to such changes. For additional information regarding the cumulative effect of changes in accounting principles we recorded in 2006 and 2005, see Note 8 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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          The following information highlights significant year-to-year variances in gross operating margin by business segment:
          NGL Pipelines & Services. Gross operating margin from this business segment was $752.5 million for 2006 compared to $579.7 million for 2005. Gross operating margin for 2006 includes $40.4 million of proceeds from business interruption insurance claims compared to $4.8 million of proceeds during 2005. Strong demand for NGLs in 2006 compared to 2005 led to higher natural gas processing margins, increased volumes of natural gas processed under fee-based contracts and higher NGL throughput volumes at certain of our pipelines and fractionation facilities. The following paragraphs provide a discussion of segment results excluding proceeds from business interruption proceeds.
          Gross operating margin from NGL pipelines and storage was $265.7 million for 2006 compared to $205.0 million for 2005. Total NGL transportation volumes increased to 1,577 MBPD during 2006 from 1,478 MBPD during 2005. The $60.7 million year-to-year increase in gross operating margin is primarily due to higher NGL transportation and storage volumes at certain of our facilities and the affects of a higher average transportation rate charged to shippers on our Mid-America pipeline. Also, segment gross operating margin in 2006 from our Dixie pipeline system benefited from lower pipeline integrity and maintenance costs year-to-year and the settlement of claims associated with a pipeline contamination incident in 2005.
          Gross operating margin from our natural gas processing and related NGL marketing business was $359.6 million for 2006 compared to $308.5 million for 2005. The $51.1 million increase in gross operating margin year-to-year is largely due to improved results from our south Texas and Louisiana natural gas processing facilities, which benefited from strong demand for NGLs, a favorable processing environment and higher levels of offshore natural gas production available for processing. Fee-based processing volumes increased to 2.2 Bcf/d during 2006 from 1.8 Bcf/d during 2005. Lastly, gross operating margin from natural gas processing for 2006 includes $9.6 million from processing contracts we acquired in connection with the Encinal acquisition in July 2006 and $9.4 million from the Pioneer facility, which we acquired from TEPPCO in March 2006.
          Gross operating margin from NGL fractionation was $86.8 million for 2006 compared to $61.5 million for 2005. Fractionation volumes increased from 292 MBPD during 2005 to 312 MBPD during 2006. The year-to-year increase in gross operating margin of $25.3 million is largely due to increased fractionation volumes at our Norco NGL fractionator. This facility suffered a reduction of volumes in the second half of 2005 due to the effects of Hurricanes Katrina and Rita. Also, our Mont Belvieu NGL fractionator benefited from a 15 MBPD expansion project that was completed during the second quarter of 2006.
          Onshore Natural Gas Pipelines & Services. Gross operating margin from this business segment was $333.4 million for 2006 compared to $353.1 million for 2005. Our total onshore natural gas transportation volumes were 6,012 BBtu/d during 2006 compared to 5,916 BBtu/d for 2005. A $24.7 million increase in segment gross operating margin from our Texas Intrastate System year-to-year was more than offset by lower gross operating margin from our San Juan Gathering System and Wilson natural gas storage facility. Gross operating margin from our Texas Intrastate System increased to $117.7 million for 2006 from $93 million for 2005 due to higher transportation fees and lower operating costs year-to-year.
          Segment gross operating margin from our San Juan Gathering System decreased $26.7 million year-to-year attributable to lower revenues from certain gathering contracts in which the fees are based on an index price for natural gas. Average index prices for natural gas were significantly higher during 2005 relative to 2006 due to supply interruptions and higher regional demand caused by Hurricanes Katrina and Rita. Natural gas gathering volumes for the San Juan Gathering System were 1,192 BBtu/d for 2006 and 1,186 BBtu/d for 2005.
          In addition, gross operating margin from this segment decreased $21.9 million year-to-year as a result of mechanical problems associated with three storage caverns located at our Wilson natural gas

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storage facility in Texas, which caused these wells to be taken out of service for most of 2006. This includes $7.9 million in losses associated with the sale of cushion gas from these wells.
          Lastly, gross operating margin for 2006 includes $1.8 million from the Encinal natural gas gathering system that we acquired in July 2006. The Encinal natural gas gathering system contributed 89 BBtu/d of gathering volumes during 2006.
          Offshore Pipelines & Services. Gross operating margin from this business segment was $103.4 million for 2006 compared to $77.5 million for 2005. Segment gross operating margin for 2006 includes $23.5 million of proceeds from business interruption insurance claims. As a result of industry losses associated with these storms, insurance costs for offshore operations have increased dramatically. Insurance costs for our offshore assets were $21.6 million for 2006 compared to $6.5 million for 2005. The following paragraphs provide a discussion of segment results excluding proceeds from business interruption proceeds.
          Gross operating margin from our offshore crude oil pipelines was $23.0 million for 2006 versus $0.3 million for 2005. Our Marco Polo and Poseidon oil pipelines posted higher crude oil transportation volumes during 2006 due to increased production activity by our customers. Collectively, gross operating margin from the Marco Polo and Poseidon oil pipelines improved $10.1 million year-to-year. Our Constitution Oil Pipeline, which was placed into service during the first quarter of 2006, contributed $8.8 million to segment gross operating margin during 2006. Total offshore crude oil transportation volumes were 153 MBPD during 2006 versus 127 MBPD during 2005.
          Gross operating margin from our offshore natural gas pipelines was $22.4 million for 2006 compared to $37.1 million for 2005. Offshore natural gas transportation volumes were 1,520 BBtu/d during 2006 versus 1,780 BBtu/d during 2005. The $14.7 million decrease in gross operating margin year-to-year is largely due to increased insurance costs and a non-cash impairment charge of $7.4 million recorded in 2006 associated with our investment in Neptune. Also, 2006 includes gross operating margin of $8.4 million and transportation volumes of 50 BBtu/d from the Constitution natural gas pipeline, which was placed in service during the first quarter of 2006.
          Gross operating margin from our offshore platforms was $34.5 million for 2006 compared to $40.1 million for 2005. The decrease in gross operating margin year-to-year is primarily due to reduced offshore production during 2006 compared to 2005 as a result of Hurricanes Katrina and Rita. Equity earnings from Deepwater Gateway, which owns the Marco Polo platform, increased $7.8 million year-to-year primarily due to higher processing volumes.
          Petrochemical Services. Gross operating margin from this business segment was $173.1 million for 2006 compared to $126.1 million for 2005. The $47.0 million year-to-year increase in gross operating margin is primarily due to improved results from our octane enhancement business attributable to higher isooctane sales volumes and prices. Gross operating margin from this business was $36.6 million for 2006 compared to $3.6 million for 2005. Isooctane, a high octane, low vapor pressure motor gasoline additive, complements the increasing use of ethanol, which has a high vapor pressure. Our isooctane production facility commenced operations in the second quarter of 2005.
          Gross operating margin from our propylene fractionation and pipeline activities was $63.4 million for 2006 versus $55.9 million for 2005. The year-to-year increase in gross operating margin of $7.5 million is primarily due to improved polymer grade propylene sales prices and volumes and the addition of the Texas City refinery-grade propylene pipeline, which we completed during 2005. Petrochemical transportation volumes were 97 MBPD during 2006 compared to 64 MBPD during 2005. Gross operating margin from butane isomerization was $73.2 million for 2006 compared to $66.6 million for 2005. The year-to-year increase of $6.6 million is primarily due to higher processing fees and lower fuel costs. Butane isomerization volumes were 81 MBPD during 2006 and 2005.

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General Outlook for 2008
          We are currently in a major asset construction phase that began in 2005. Fiscal 2007 was a transitional year as we completed construction of several major projects and placed them into service for a portion of 2007. These projects included the Independence Hub platform and Trail pipeline, Meeker natural gas processing plant, Hobbs NGL fractionator, expansion of Mid-America NGL pipeline and a new propylene fractionator at Mont Belvieu. Additionally, in February 2008, we placed the Pioneer cryogenic natural gas processing plant in service. In 2008, we expect these major projects to contribute significant new sources of revenue, operating income and cash flow from operations as volumes increase to these facilities.
          During the second half of 2008, construction of additional growth projects should be completed; placed in service and begin to contribute new sources of revenue, operating income and cash flow from operations. These include the expansion of the Meeker natural gas processing plant, Exxon central treating facility and the Sherman Extension natural gas pipeline.
          We are continuing to work to expand our relationships with existing customers and pursue service agreements with new customers that would provide additional volumes to both our existing and newly constructed assets. Based on current general and industry economic conditions,
  §   We believe that drilling and production activities in the major producing areas where we operate, including the Gulf of Mexico and supply basins in Texas, San Juan and the Rocky Mountains, could result in increased demand for our midstream energy services. As a result, we expect higher transportation and processing volumes for certain of our existing and newly constructed assets due to increased natural gas, NGL and crude oil production from both onshore and offshore producing areas.
 
  §   We expect the volume of natural gas and NGLs available to our facilities in Texas to increase as a result of drilling activity and long-term agreements executed with new customers. We expect natural gas transportation volumes on our Texas Intrastate System to increase during 2008 as we supply the Houston, Texas area with natural gas volumes under a long-term agreement with CenterPoint Energy and begin operations on the Sherman Extension pipeline in the Barnett Shale region of North Texas in the fourth quarter of 2008.
 
  §   We believe that the current strength of the domestic and global economies should continue to drive increased demand for all forms of energy despite fluctuating commodity prices. Our largest NGL consuming customers in the ethylene industry continue to see strong demand for their products. Ethane and propane continue to be the preferred feedstocks for the ethylene industry due to the higher cost of crude oil derivatives.
 
  §   Longer term, we believe the expansion of crude oil refineries on the U.S. Gulf Coast could result in opportunities to provide additional midstream services through our existing assets and support the construction of new pipeline and storage facilities.
Liquidity and Capital Resources
          Our primary cash requirements, in addition to normal operating expenses and debt service, are for working capital, capital expenditures, business acquisitions and distributions to our partners. We expect to fund our short-term needs for such items as operating expenses and sustaining capital expenditures with operating cash flows and short-term revolving credit arrangements. Capital expenditures for long-term needs resulting from internal growth projects and business acquisitions are expected to be funded by a variety of sources (either separately or in combination) including net cash flows provided by operating activities, borrowings under credit facilities, the issuance of additional equity and debt securities and proceeds from divestitures of ownership interest in assets to affiliates or third parties. We expect to fund cash distributions to partners primarily with operating cash flows. Our debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements.

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          At December 31, 2007, we had $39.7 million of unrestricted cash on hand and approximately $1.02 billion of available credit under EPO’s Multi-Year Revolving Credit Facility. In total, we had approximately $6.90 billion in principal outstanding under consolidated debt agreements at December 31, 2007. For detailed information regarding our consolidated debt obligations and those of our unconsolidated affiliates, see Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
          As a result of our growth objectives, we expect to access debt and equity capital markets from time-to-time and we believe that financing arrangements to support our growth activities can be obtained on reasonable terms. Furthermore, we believe that maintenance of an investment grade credit rating combined with continued ready access to debt and equity capital at reasonable rates and sufficient trade credit to operate our businesses efficiently provide a solid foundation to meet our long and short-term liquidity and capital resource requirements.
     Registration Statements
          We may issue equity or debt securities to assist us in meeting our liquidity and capital spending requirements. Duncan Energy Partners may do likewise in meeting its liquidity and capital spending requirements. Enterprise Products Partners L.P. and EPO have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (“SEC”) that would allow these entities to issue an unlimited amount of debt and equity securities for general partnership purposes.
          During 2003, we instituted a distribution reinvestment plan (“DRIP”). We have a registration statement on file with the SEC covering the issuance of up to 25,000,000 common units in connection with the DRIP. The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional common units. During the year ended December 31, 2007, we issued 1,923,640 common units in connection with our DRIP, which generated proceeds of $56.3 million from plan participants.
          We also have a registration statement on file related to our employee unit purchase plan, under which we can issue up to 1,200,000 common units. Under this plan, employees of EPCO can purchase our common units at a 10% discount through payroll deductions. During the year ended December 31, 2007, we issued 132,975 common units to employees under this plan, which generated proceeds of $4.0 million.
          In February 2007, Duncan Energy Partners completed its initial public offering of 14,950,000 common units, the majority of proceeds from which were distributed to us. Duncan Energy Partners may issue additional amounts of equity in the future in connection with other acquisitions. For additional information regarding Duncan Energy Partners, see “Other Items — Initial Public Offering of Duncan Energy Partners” within this Item 7.
          For information regarding our public debt obligations or partnership equity, see Notes 14 and 15, respectively, of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
     Credit Ratings of EPO
          At February 1, 2008, the investment-grade credit ratings of EPO’s debt securities were Baa3 by Moody’s Investor Services; BBB- by Fitch Ratings; and BBB- by Standard and Poor’s. A rating reflects only the view of a rating agency and is not a recommendation to buy, sell or hold any security. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it determines that the circumstances warrant such a change and should be evaluated independently of any other rating.
          Based on the characteristics of the $1.25 billion of fixed/floating unsecured junior subordinated notes that EPO issued in 2006 and 2007, the rating agencies assigned partial equity treatment to the notes.

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Moody’s Investor Services and Standard and Poor’s each assigned 50% equity treatment and Fitch Ratings assigned 75% equity treatment.
          In connection with the construction of our Pascagoula, Mississippi natural gas processing plant, EPO entered into a $54 million, ten-year, fixed-rate loan with the Mississippi Business Finance Corporation (“MBFC”). The indenture agreement for this loan contains an acceleration clause whereby if EPO’s credit rating by Moody’s Investor Services declines below Baa3 in combination with our credit rating at Standard & Poor’s declining below BBB-, the $54.0 million principal balance of this loan, together with all accrued and unpaid interest would become immediately due and payable 120 days following such event. If such an event occurred, EPO would have to either redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to support its obligation under this loan.
     Cash Flows from Operating, Investing and Financing Activities
          The following table summarizes our cash flows from operating, investing and financing activities for the periods indicated (dollars in thousands). For information regarding the individual components of our cash flow amounts, see the Statements of Consolidated Cash Flows included under Item 8 of this annual report.
                         
    For the Year Ended December 31,
    2007   2006   2005
     
Net cash flows provided by operating activities
  $ 1,590,941     $ 1,175,069     $ 631,708  
Cash used in investing activities
    2,533,607       1,689,288       1,130,395  
Cash provided by financing activities
    979,355       494,972       516,229  
          Net cash flows provided by operating activities is largely dependent on earnings from our business activities. As a result, these cash flows are exposed to certain risks. We operate predominantly in the midstream energy industry. We provide services for producers and consumers of natural gas, NGLs and crude oil. The products that we process, sell or transport are principally used as fuel for residential, agricultural and commercial heating; feedstocks in petrochemical manufacturing; and in the production of motor gasoline. Reduced demand for our services or products by industrial customers, whether because of general economic conditions, reduced demand for the end products made with our products or increased competition from other service providers or producers due to pricing differences or other reasons could have a negative impact on our earnings and thus the availability of cash from operating activities. For a more complete discussion of these and other risk factors pertinent to our business, see Item 1A of this annual report.
          Our Statements of Consolidated Cash Flows are prepared using the indirect method. The indirect method derives net cash flows from operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in inventory, deferred income and similar transactions, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, (iii) the effects of all items classified as investing or financing cash flows, such as gains or losses on sale of property, plant and equipment or extinguishment of debt, and (iv) other non-cash amounts such as depreciation, amortization, operating lease expense paid by EPCO and changes in the fair market value of financial instruments. Equity in income from unconsolidated affiliates is also a non-cash item that must be removed in determining net cash provided by operating activities. Our cash flows from operating activities reflect the actual cash distributions we receive from such investees.
          In general, the net effect of changes in operating accounts results from the timing of cash receipts from sales and cash payments for purchases and other expenses during each period. Increases or decreases in inventory are influenced by the quantity of products held in connection with our marketing activities and changes in energy commodity prices.
          Cash used in investing activities primarily represents expenditures for capital projects, business combinations, asset purchases and investments in unconsolidated affiliates. Cash provided by (or used in)

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financing activities generally consists of borrowings and repayments of debt, distributions to partners and proceeds from the issuance of equity securities. Amounts presented in our Statements of Consolidated Cash Flows for borrowings and repayments under debt agreements are influenced by the magnitude of cash receipts and payments under our revolving credit facilities.
          The following information highlights the significant year-to-year variances in our cash flow amounts:
Comparison of 2007 with 2006
          Operating activities. Net cash flow provided by operating activities was $1.59 billion for the year ended December 31, 2007 compared to $1.18 billion for the year ended December 31, 2006.
  §   Our net cash flows from consolidated businesses (excluding cash payments for interest and taxes and distributions received from unconsolidated affiliates) increased $436.9 million year-to-year. The improvement in cash flow is generally due to increased gross operating margin (see “Results of Operations” within this Item 7) and the timing of related cash collections and disbursements between periods. The $436.9 million year-to-year increase also includes a $42.1 million increase in cash proceeds we received from insurance claims related to certain named storms. See Note 21 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding insurance matters.
 
  §   Cash distributions received from unconsolidated affiliates increased $30.6 million year-to-year primarily due to improved earnings from our Gulf of Mexico investments, which were negatively impacted during the year ended December 31, 2006 as a result of the lingering effects of Hurricanes Katrina and Rita.
 
  §   Cash payments for interest increased $56.2 million year-to-year primarily due to increased borrowings to finance our capital spending program. Our average debt balance for the year ended December 31, 2007 was $6.26 billion compared to $4.93 billion for the year ended December 31, 2006.
 
  §   Cash payments for federal and state income taxes decreased $4.7 million year-to-year.
          Investing activities. Cash used in investing activities was $2.55 billion for the year ended December 31, 2007 compared to $1.69 billion for the year ended December 31, 2006. The $864.3 million year-to-year increase in cash outflows is primarily due to an $847.7 million increase in capital spending for property, plant and equipment and a $194.6 million increase in investments in unconsolidated affiliates, partially offset by a $240.7 million decrease in cash outlays for business combinations. For additional information related to our capital spending for property, plant and equipment, see “Capital Spending” included within this Item 7.
          During the year ended December 31, 2007 we contributed $216.5 million to an unconsolidated affiliate, Cameron Highway Oil Pipeline Company (“Cameron Highway”). In return, Cameron Highway used these funds, along with an equal contribution from our 50% joint venture partner in Cameron Highway, to repay its $430.0 million in outstanding debt.
          During the year ended December 31, 2006, we paid $100.0 million for a 100% interest in Piceance Creek Pipeline, LLC and paid Lewis Energy Group, L.P. (“Lewis”) $145.2 million in cash in connection with the Encinal acquisition. Our spending for business combinations during the year ended December 31, 2007 was primarily limited to the $35.0 million we paid to acquire the South Monco pipeline business.
          Financing activities. Cash provided by financing activities was $979.4 million for the year ended December 31, 2007 versus $495.0 million for the year ended December 31, 2006. The following information highlights significant factors that influenced the $484.4 million year-to-year change in cash provided by financing activities:
  §   Net borrowings under our consolidated debt agreements increased $1.10 billion year-to-year. In May 2007, EPO sold $700.0 million in principal amount of fixed/floating unsecured junior subordinated notes (Junior Notes B”). In September 2007, EPO sold $800.0 million in principal

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      amount of fixed-rate unsecured senior notes (“Senior Notes L”) and in October 2007, EPO repaid $500.0 million in principal amount of Senior Notes E. For information regarding our consolidated debt obligations, see Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
 
  §   Net proceeds from the issuance of our common units decreased $788.0 million year-to-year. We had underwritten equity offerings in March and September of 2006 that generated net proceeds of $750.8 million reflecting the sale of 31,050,000 common units.
 
  §   Contributions from minority interests increased $275.4 million year-to-year primarily due to the initial public offering of Duncan Energy Partners in February 2007, which generated net proceeds of $290.5 million from the sale of 14,950,000 of its common units. See “Other Items — Initial Public Offering of Duncan Energy Partners” within this Item 7 for additional information regarding this offering.
 
  §   Cash distributions to our partners increased $137.9 million year-to-year due to an increase in common units outstanding and our quarterly cash distribution rates.
 
  §   We received $48.9 million from the settlement of treasury lock contracts during the year ended December 31, 2007 related to our interest rate hedging activities.
Comparison of 2006 with 2005
          Operating activities. Net cash flow provided by operating activities was $1.18 billion for the year ended December 31, 2006 compared to $631.7 million for the year ended December 31, 2006.
  §   Our net cash flows from consolidated businesses (excluding cash payments for interest and taxes and distributions received from unconsolidated affiliates) increased $569.6 million year-to-year. The improvement in cash flow is generally due to increased earnings (see “Results of Operations” within this Item 7) and the timing of related cash collections and disbursements between periods. The $569.6 million year-to-year increase also includes a $93.7 million increase in cash proceeds we received from insurance claims related to certain named storms.
 
  §   Cash distributions received from unconsolidated affiliates decreased $13.0 million year-to-year primarily due to the lingering effects of Hurricanes Katrina and Rita on our Gulf of Mexico investments during the year ended December 31, 2006.
 
  §   Cash payments for interest increased $7.9 million year-to-year. Our average debt balance for the year ended December 31, 2006 was $4.93 billion compared to $4.63 billion for the year ended December 31, 2005.
 
  §   Cash payments for federal and state income taxes increased $5.3 million year-to-year.
          Investing activities. Cash used in investing activities was $1.7 billion for the year ended December 31, 2006 compared to $1.1 billion for the year ended December 31, 2005. Our cash outlays for business combinations were $276.5 million in 2006 versus $326.6 million in 2005. During the year ended December 31, 2006, we paid $100.0 million for a 100% interest in Piceance Creek Pipeline, LLC and paid Lewis $145.2 million in cash in connection with the Encinal acquisition. Our cash outlay for acquisitions during 2005 included (i) $145.5 million for storage assets purchased from Ferrellgas LP, (ii) $74.9 million for indirect interests in certain East Texas natural gas gathering and processing assets, (iii) $68.6 million for additional ownership interests in Dixie and (iv) $25.0 million for the remaining ownership interests in our Mid-America Pipeline System and an additional interest in the Seminole Pipeline.
          Proceeds from the sale of assets during 2005 include $42.1 million from the sale of our investment in Starfish Pipeline Company, LLC (“Starfish”). We were required to divest our ownership interest in this entity by the Federal Trade Commission in order to gain its approval for our merger with GulfTerra Energy Partners, L.P. in September 2004. In addition, we received $47.5 million as a return of our investment in

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Cameron Highway in June 2005. As a result of refinancing its project debt, Cameron Highway was authorized by its lenders to make this special distribution.
          Investments in unconsolidated affiliates were $138.3 million for the year ended December 31, 2006 compared to $87.3 million for the year ended December 31, 2005. The 2006 period includes $120.1 million we invested to date in the Phase V expansion project of Jonah. The 2005 period primarily reflects $72.0 million we contributed to Deepwater Gateway to fund our share of the repayment of its construction loan in March 2005.
          For additional information related to our capital spending program, see “Capital Spending” included within this Item 7.
          Financing activities Cash provided by financing activities was $495.0 million for the year ended December 31, 2006 compared to $516.2 million for the year ended December 31, 2005. As a result of our capital spending program, we utilized EPO’s Multi-Year Revolving Credit Facility in varying degrees throughout 2006. During 2006, we applied all or a portion of the net proceeds from equity and debt offerings to reduce debt outstanding. We used $430 million of net proceeds from our March 2006 equity offering and $260 million of net proceeds from our September 2006 equity offering to temporarily reduce amounts due under EPO’s Multi-Year Revolving Credit Facility. We also used the net proceeds from the EPO’s issuance of Junior Subordinated Notes A in the third quarter of 2006 to reduce debt outstanding under this facility. We used any remaining net proceeds from these offerings in 2006 for general partnership purposes.
          During 2005, our EPO issued an aggregate of $1 billion in senior notes, the proceeds of which were used to repay $350.0 million due under Senior Notes A, to temporarily reduce amounts outstanding under our bank credit facilities and for general partnership purposes. Additionally, we repaid the remaining $242.2 million that was due under EPO’s 364-Day Acquisition Credit Facility (which was used to finance elements of the GulfTerra Merger) using proceeds generated from our February 2005 equity offering.
          Net proceeds from the issuance of our limited partner interests were $857.2 million for 2006 compared to $646.9 million for 2005. With respect to equity offerings (including sales through our distribution reinvestment program and employee unit purchase plan), we issued 34,824,649 common units 2006 versus 23,979,740 common units during 2005. Net proceeds from underwritten equity offerings were $750.8 million during 2006 reflecting the sale of 31,050,000 common units and $555.5 million during 2005 reflecting the sale of 21,250,000 common units. Our distribution reinvestment program and related employee unit purchase plan generated net proceeds of $96.9 million during 2006, including $50 million reinvested by EPCO. In comparison, this program generated proceeds of $69.7 million during 2005, including $30 million reinvested by EPCO.
          Cash distributions to partners increased from $716.7 million during 2005 to $843.3 million during 2006. The year-to-year increase in cash distributions is due to an increase in common units outstanding and quarterly cash distribution rates. Cash contributions from minority interests were $27.6 million for 2006 compared to $39.1 million for 2005.
     Capital Spending
          An integral part of our business strategy involves expansion through business combinations, growth capital projects and investments in joint ventures. We believe that we are positioned to continue to grow our system of assets through the construction of new facilities and to capitalize on expected increases in natural gas and/or crude oil production from resource basins such as the Piceance Basin of western Colorado, the Greater Green River Basin in Wyoming, Barnett Shale in North Texas, and the deepwater Gulf of Mexico.
          Management continues to analyze potential acquisitions, joint ventures and similar transactions with businesses that operate in complementary markets or geographic regions. In recent years, major oil and gas companies have sold non-strategic assets in the midstream energy sector in which we operate. We

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forecast that this trend will continue, and expect independent oil and natural gas companies to consider similar divestitures.
          The following table summarizes our capital spending by activity for the periods indicated (dollars in thousands):
                         
    For the Year Ended December 31,
    2007   2006   2005
     
Capital spending for business combinations:
                       
Encinal acquisition, excluding non-cash consideration (1)
  $ 114     $ 145,197     $  
Piceance Basin Gathering System acquisition
    368       100,000        
South Monco Pipeline System acquisition
    35,000              
Canadian Enterprise Gas Products acquisition
          17,690        
NGL underground storage and terminalling assets purchased from Ferrellgas
                145,522  
Indirect interests in the Indian Springs natural gas gathering and processing assets
                74,854  
Additional ownership interests in Dixie Pipeline Company (“Dixie”)
    311       12,913       68,608  
Additional ownership interests in Mid-America and Seminole pipeline systems
                25,000  
Other business combinations
          700       12,618  
     
Total
    35,793       276,500       326,602  
     
Capital spending for property, plant and equipment, net: (2)
                       
Growth capital projects (3)
    1,986,157       1,148,123       719,372  
Sustaining capital projects (4)
    142,096       132,455       98,077  
     
Total
    2,128,253       1,280,578       817,449  
     
Capital spending for intangible assets:
                       
Acquisition of intangible assets
    11,232              
     
Total
    11,232              
     
Capital spending attributable to unconsolidated affiliates:
                       
Investments in unconsolidated affiliates (5)
    343,009       127,422       88,044  
     
Total
    343,009       127,422       88,044  
     
Total capital spending
  $ 2,518,287     $ 1,684,500     $ 1,232,095  
     
 
(1)   Excludes $181.1 million of non-cash consideration paid to the seller in the form of 7,115,844 of our common units. See Note 12 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for additional information regarding our business combinations.
 
(2)   On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins. Contributions in aid of construction costs were $57.5 million, $60.5 million and $47.0 million for the years ended December 31, 2007, 2006 and 2005, respectively.
 
(3)   Growth capital projects either result in additional revenue streams from existing assets or expand our asset base through construction of new facilities that will generate additional revenue streams.
 
(4)   Sustaining capital expenditures are capital expenditures (as defined by GAAP) resulting from improvements to and major renewals of existing assets. Such expenditures serve to maintain existing operations but do not generate additional revenues.
 
(5)   Fiscal 2007 includes $216.5 million in cash contributions to Cameron Highway Oil Pipeline Company (“Cameron Highway”) to fund our share of the repayment of its debt obligations.
          Based on information currently available, we estimate our consolidated capital spending for 2008 will approximate $1.7 billion, which includes estimated expenditures of $1.5 billion for growth capital projects and acquisitions and $0.2 billion for sustaining capital expenditures.
          Our forecast of consolidated capital expenditures is based on our current strategic operating and growth plans, which are dependent upon our ability to generate the required funds from either operating cash flows or from other means, including borrowings under debt agreements, issuance of equity, and potential divestitures of certain assets to third and/or related parties. Our forecast of capital expenditures may change due to factors beyond our control, such as weather related issues, changes in supplier prices or adverse economic conditions. Furthermore, our forecast may change as a result of decisions made by management at a later date, which may include acquisitions or decisions to take on additional partners.

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          Our success in raising capital, including the formation of joint ventures to share costs and risks, continues to be a principal factor that determines how much capital we can invest. We believe our access to capital resources is sufficient to meet the demands of our current and future operating growth needs, and although we currently intend to make the forecasted expenditures discussed above, we may adjust the timing and amounts of projected expenditures in response to changes in capital markets.
          At December 31, 2007, we had approximately $569.7 million in purchase commitments outstanding that relate to our capital spending for property, plant and equipment. These commitments primarily relate to construction of our Barnett Shale natural gas pipeline project and Meeker and Pioneer natural gas processing plants.
          Significant Ongoing Growth Capital Projects
          The following table summarizes information regarding our current significant growth capital projects as of February 1, 2008 (dollars in millions). The capital spending amount noted for each project at December 31, 2007 includes accrued expenditures and capitalized interest as of this date. The forecast amount noted for each project includes a provision for estimated capitalized interest.
                         
            Actual   Current
    Estimated   Costs Through   Forecast
    Date of   December 31,   Total
Project Name   Completion   2007   Cost
 
Pioneer II natural gas processing plant
  First Quarter 2008   $ 279.9     $ 360.2  
Expansion of Petal natural gas storage facility
  Second Quarter 2008     65.3       96.5  
Meeker II natural gas processing plant
  Third Quarter 2008     137.5       399.5  
Sherman Extension Pipeline (Barnett Shale)
  Fourth Quarter 2008     30.9       477.9  
ExxonMobil Conditioning & Treating Facility — Piceance Basin
  Fourth Quarter 2008     122.3       195.4  
Mont Belvieu Storage Well Optimization Projects
  Fourth Quarter 2008     131.0       180.5  
Shenzi Oil Pipeline
    2009       76.2       171.2  
Marathon Piceance Basin pipeline projects
    2009       3.3       114.8  
Expansion of Wilson natural gas storage facility
    2010       2.4       113.7  
          Pioneer cryogenic natural gas processing plant. In July 2006, we began construction of a cryogenic natural gas processing plant located adjacent to the silica gel plant we acquired from TEPPCO in March 2006 and subsequently expanded. The Pioneer cryogenic facility commenced operations in February 2008. This new facility has a processing capacity of 750 MMcf/d and can handle expected production growth from the Jonah and Pinedale fields located in the Greater Green River Basin in Wyoming. At full rates, the Pioneer cryogenic facility is expected to recover up to 30 MBPD of NGLs.
          Expansion of Petal natural gas storage facility. We are developing a new natural gas storage cavern located on the Petal Salt Dome near Petal, Mississippi. The 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 Federal Energy Regulatory Commission and is projected to commence operations during the second quarter of 2008. We have long-term, binding precedent agreements on the majority of the capacity.
          Meeker II natural gas processing plant. 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.
          Sherman Extension Pipeline (Barnett Shale). 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. The Sherman Extension is

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supported by long-term contracts with Devon Energy Corporation, the largest producer in the Barnett Shale area, and significant indications of interest from leading producers and gatherers in the Fort Worth basin, as well as other shippers on our Texas Intrastate Pipeline system. At its terminus, the new pipeline system will make deliveries into Boardwalk Pipeline Partners L.P.’s (“Boardwalk”) Gulf Crossing Expansion Project, which will provide export capacity for Barnett Shale natural gas production to multiple delivery points in Louisiana, Mississippi and Alabama that offer access to attractive markets in the Northeast and Southeast United States. In addition, the Sherman Extension will provide natural gas producers in East Texas and the Waha area of West Texas with access to these higher value markets through our Texas Intrastate Pipeline system. The Sherman Extension will originate near Morgan Mill, Texas and extend through the center of the current Barnett Shale development area to Sherman, Texas.
          The Barnett Shale is considered to be one of the largest unconventional natural gas resource plays in North America, covering approximately 14 counties and over seven million acres in the Fort Worth basin in North Texas. Current natural gas production is estimated at 3.4 Bcf/d from approximately 7,800 wells. Approximately 190 rigs are currently estimated to be working to develop Barnett Shale acreage in the region. According to the United States Geological Survey, the Barnett Shale has the resource potential of approximately 26 trillion cubic feet of natural gas.
          ExxonMobil Conditioning & Treating Facility — Piceance Basin. In November 2006, we entered into a 30-year agreement with Exxon Mobil Corporation (“ExxonMobil”) to provide gathering, compression, treating and conditioning services for natural gas produced from its Piceance Creek Development Project, which encompasses more than 29,000 acres in Rio Blanco County, Colorado. Under terms of the agreement, ExxonMobil dedicated all of its natural gas production from this development to us for processing. To provide these services, we are constructing new plant and pipeline facilities to compress the natural gas, treat it to remove impurities, extract NGLs, and deliver the gas to various pipeline transmission systems that serve the region.
          Mont Belvieu Storage Well Optimization Projects. These projects are designed to improve our ability and efficiency of storing and handling NGLs and other products at our Mont Belvieu Caverns underground storage facility. These projects include new pipelines that interconnect our three storage facilities in Mont Belvieu (i.e. East, West and North locations) as well as a brine pipeline that interconnects our various above ground storage pits. Also included in this effort are several infrastructure related projects that will allow us to handle higher inbound and outbound NGL injection rates into and out of the caverns. In general this series of projects should allow us to better utilize our current asset base and allow for future growth.
          Shenzi Oil Pipeline. In October 2006, we announced the execution of definitive agreements with producers to construct, own and operate an oil export pipeline that will provide firm gathering services from the BHP Billiton Plc-operated Shenzi production field located in the South Green Canyon area of the central Gulf of Mexico. The Shenzi oil export pipeline will originate at the Shenzi Field, located in 4,300 feet of water at Green Canyon Block 653, approximately 120 miles off the coast of Louisiana. The 83-mile, 20-inch diameter pipeline will have the capacity to transport up to 230 MBPD of crude oil and will connect the Shenzi Field to our Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System at our Ship Shoal 332B junction platform. We own a 50% interest in the Cameron Highway Oil Pipeline and a 36% interest in the Poseidon Oil Pipeline System and operate both pipelines. The Shenzi oil export pipeline will connect to a platform being constructed by BHP Billiton Plc to develop the Shenzi Field, which is expected to begin production in mid-2009.
          Marathon Piceance Basin pipeline projects. In December 2006, we entered into a long-term contract with Marathon Oil Company (“Marathon”) to provide a range of midstream energy services, including natural gas gathering, compression, treating and processing, for Marathon’s natural gas production in the Piceance Basin of northwest Colorado. Under the terms of the contract, we are constructing fifty miles of gathering lines to connect Marathon’s multi-well drilling sites, production from which is expected to peak at approximately 180 MMcf/d, to our Piceance Creek Gathering System. From there, the natural gas will be delivered to our Meeker natural gas processing facility.

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          Expansion of Wilson natural gas storage facility. We are developing a new natural gas storage cavern located on the Boling Salt Dome near Boling, Texas. The 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 Texas Railroad Commission and is projected to commence operations in 2010. We expect to secure binding precedent agreements on all capacity before the cavern commences operations.
     Pipeline Integrity Costs
          Our NGL, petrochemical and natural gas pipelines are subject to pipeline safety programs administered by the U.S. Department of Transportation, through its Office of Pipeline Safety. This federal agency has issued safety regulations containing requirements for the development of integrity management programs for hazardous liquid pipelines (which include NGL and petrochemical pipelines) and natural gas pipelines. In general, these regulations require companies to assess the condition of their pipelines in certain high consequence areas (as defined by the regulation) and to perform any necessary repairs.
          In April 2002, a subsidiary of ours acquired several midstream energy assets located in Texas and New Mexico from El Paso Corporation (“El Paso”). These assets included the Texas Intrastate System and the Waha and Carlsbad Gathering Systems. With respect to such assets, El Paso agreed to indemnify our subsidiary for any pipeline integrity costs it incurred (whether paid or payable) for five years following the acquisition date. The indemnity provisions did not take effect until such costs exceeded $3.3 million annually; however, the amount reimbursable by El Paso was capped at $50.2 million in the aggregate. In 2007 and 2006, we recovered $31.1 million and $13.7 million, respectively from El Paso related to our 2006 and 2005 expenditures. During 2007, we received a final amount of $5.4 million from El Paso related to this indemnity.
          The following table summarizes our pipeline integrity costs, net of indemnity payments from El Paso, for the periods indicated (dollars in thousands):
                         
    For the Year Ended December 31,
    2007   2006   2005
     
Expensed
  $ 43,499     $ 26,397     $ 17,245  
Capitalized
    52,420       38,180       24,964  
     
Total
  $ 95,919     $ 64,577     $ 42,209  
     
          We expect our cash outlay for the pipeline integrity program, irrespective of whether such costs are capitalized or expensed to approximate $65 million in 2008.
Critical Accounting Policies and Estimates
          In our financial reporting process, we employ methods, estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of our financial statements. These methods, estimates and assumptions also affect the reported amounts of revenues and expenses during the reporting period. Investors should be aware that actual results could differ from these estimates if the underlying assumptions prove to be incorrect. The following describes the estimation risk currently underlying our most significant financial statement items:
     Depreciation methods and estimated useful lives of property, plant and equipment
          In general, depreciation is the systematic and rational allocation of an asset’s cost, less its residual value (if any), to the periods it benefits. The majority of our property, plant and equipment is depreciated using the straight-line method, which results in depreciation expense being incurred evenly over the life of the assets. Our estimate of depreciation incorporates assumptions regarding the useful economic lives and residual values of our assets. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation amounts prospectively.

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          Examples of such circumstances include:
       
 
  §   changes in laws and regulations that limit the estimated economic life of an asset;
 
  §   changes in technology that render an asset obsolete;
 
  §   changes in expected salvage values; or
 
  §   changes in the forecast life of applicable resource basins, if any.
          At December 31, 2007 and 2006, the net book value of our property, plant and equipment was $11.59 billion and $9.83 billion, respectively. We recorded $414.9 million, $350.8 million, and $328.7 million in depreciation expense for the years ended December 31, 2007, 2006 and 2005, respectively.
          For additional information regarding our property, plant and equipment, see Notes 2 and 10 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
     Measuring recoverability of long-lived assets and equity method investments
          In general, long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. Examples of such events or changes might be production declines that are not replaced by new discoveries or long-term decreases in the demand or price of natural gas, oil or NGLs. Long-lived assets with recorded values that are not expected to be recovered through expected future cash flows are written-down to their estimated fair values. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of undiscounted estimated cash flows expected to result from the use and eventual disposition of the existing asset. Our estimates of such undiscounted cash flows are based on a number of assumptions including anticipated operating margins and volumes; estimated useful life of the asset or asset group; and estimated salvage values. An impairment charge would be recorded for the excess of a long-lived asset’s carrying value over its estimated fair value, which is based on a series of assumptions similar to those used to derive undiscounted cash flows. Those assumptions also include usage of probabilities for a range of possible outcomes, market values and replacement cost estimates.
          An equity method investment is evaluated for impairment whenever events or changes in circumstances indicate that there is a possible loss in value of the investment other than a temporary decline. Examples of such events include sustained operating losses of the investee or long-term negative changes in the investee’s industry. The carrying value of an equity method investment is not recoverable if it exceeds the sum of discounted estimated cash flows expected to be derived from the investment. This estimate of discounted cash flows is based on a number of assumptions including discount rates; probabilities assigned to different cash flow scenarios; anticipated margins and volumes and estimated useful life of the investment. A significant change in these underlying assumptions could result in our recording an impairment charge.
          We recognized a non-cash asset impairment charge related to property, plant and equipment of $0.1 million in 2006, which is reflected as a component of operating costs and expenses. No such asset impairment charges were recorded in 2007 and 2005.
          During 2007, we evaluated our equity method investment in Nemo Gathering Company, LLC for impairment. As a result of this evaluation, we recorded a $7.0 million non-cash impairment charge that is a component of equity income from unconsolidated affiliates for the year ended December 31, 2007. Similarly, during the year ended December 31, 2006, we evaluated our equity method investment in Neptune Pipeline Company, L.L.C. for impairment and recorded a $7.4 million non-cash impairment charge. We had no such impairment charges during the year ended December 31, 2005.

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          For additional information regarding impairment charges associated with our long-lived assets and equity method investments, see Notes 2 and 11 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
     Amortization methods and estimated useful lives of qualifying intangible assets
          The specific, identifiable intangible assets of a business enterprise depend largely upon the nature of its operations. Potential intangible assets include intellectual property, such as technology, patents, trademarks and trade names, customer contracts and relationships, and non-compete agreements, as well as other intangible assets. The method used to value each intangible asset will vary depending upon the nature of the asset, the business in which it is utilized, and the economic returns it is generating or is expected to generate.
          Our customer relationship intangible assets primarily represent the customer base we acquired in connection with business combinations and asset purchases. The value we assigned to these customer relationships is being amortized to earnings using methods that closely resemble the pattern in which the economic benefits of the underlying oil and natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. Our estimate of the useful life of each resource base is based on a number of factors, including reserve estimates, the economic viability of production and exploration activities and other industry factors.
          Our contract-based intangible assets represent the rights we own arising from discrete contractual agreements, such as the long-term rights we possess under the Shell natural gas processing agreement. A contract-based intangible asset with a finite life is amortized over its estimated useful life (or term), which is the period over which the asset is expected to contribute directly or indirectly to the cash flows of an entity. Our estimates of useful life are based on a number of factors, including:
  §   the expected useful life of the related tangible assets (e.g., fractionation facility, pipeline, etc.);
 
  §   any legal or regulatory developments that would impact such contractual rights; and
 
  §   any contractual provisions that enable us to renew or extend such agreements.
          If our underlying assumptions regarding the estimated useful life of an intangible asset change, then the amortization period for such asset would be adjusted accordingly. Additionally, if we determine that an intangible asset’s unamortized cost may not be recoverable due to impairment; we may be required to reduce the carrying value and the subsequent useful life of the asset. Any such write-down of the value and unfavorable change in the useful life of an intangible asset would increase operating costs and expenses at that time.
          At December 31, 2007 and 2006, the carrying value of our intangible asset portfolio was $917.0 million and $1.0 billion, respectively. We recorded $89.7 million, $88.8 million, and $88.9 million in amortization expense associated with our intangible assets for the years ended December 31, 2007, 2006 and 2005, respectively.
          For additional information regarding our intangible assets, see Notes 2 and 13 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
     Methods we employ to measure the fair value of goodwill
          Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values. We do not amortize goodwill; however, we test our goodwill (at the reporting unit level) for impairment during the second quarter of each fiscal year, and more frequently, if circumstances indicate it is more likely than not that the fair value of goodwill is below its carrying amount. Our goodwill testing involves the determination of a reporting unit’s fair value, which is predicated on our assumptions regarding the future economic prospects of the reporting unit.

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          Such assumptions include:
       
 
  §   discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins and transportation volumes;
 
  §   long-term growth rates for cash flows beyond the discrete forecast period; and
 
  §   appropriate discount rates.
          If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, a charge to earnings is required to reduce the carrying value of goodwill to its implied fair value. At December 31, 2007 and 2006, the carrying value of our goodwill was $591.7 million and $590.5 million, respectively. We did not record any goodwill impairment charges during the years ended December 31, 2007, 2006 and 2005.
          For additional information regarding our goodwill, see Notes 2 and 13 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
     Our revenue recognition policies and use of estimates for revenues and expenses
          In general, we recognize revenue from our customers when all of the following criteria are met:
       
 
  §   persuasive evidence of an exchange arrangement exists;
 
  §   delivery has occurred or services have been rendered;
 
  §   the buyer’s price is fixed or determinable; and
 
  §   collectability is reasonably assured.
          We record revenue when sales contracts are settled (i.e., either physical delivery of product has taken place or the services designated in the contract have been performed). We record any necessary allowance for doubtful accounts as required by our established policy.
          Our use of certain estimates for revenues and expenses has increased as a result of SEC regulations that require us to submit financial information on accelerated time frames. Such estimates are necessary due to the timing of compiling actual billing information and receiving third-party data needed to record transactions for financial reporting purposes. One example of such use of estimates is the accrual of an estimate of processing plant revenue and the cost of natural gas for a given month (prior to receiving actual customer and vendor-related plant operating information for the subject period). These estimates reverse in the following month and are offset by the corresponding actual customer billing and vendor-invoiced amounts. Accordingly, we include one month of certain estimated data in our results of operations. Such estimates are generally based on actual volume and price data through the first part of the month and estimated for the remainder of the month, adjusted accordingly for any known or expected changes in volumes or rates through the end of the month.
          If the basis of our estimates proves to be substantially incorrect, it could result in material adjustments in results of operations between periods. On an ongoing basis, we review our estimates based on currently available information. Changes in facts and circumstances may result in revised estimates and could affect our reported financial statements and accompanying notes.
Reserves for environmental matters
          Each of our business segments is subject to federal, state and local laws and regulations governing environmental quality and pollution control. Such laws and regulations may, in certain instances, require us to remediate current or former operating sites where specified substances have been released or disposed

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of. We accrue reserves for environmental matters when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Our assessments are based on studies, as well as site surveys, to determine the extent of any environmental damage and the necessary requirements to remediate this damage. Future environmental developments, such as increasingly strict environmental laws and additional claims for damages to property, employees and other persons resulting from current or past operations, could result in substantial additional costs beyond our current reserves.
          At December 31, 2007 and 2006, we had a liability for environmental remediation of $26.5 million and $24.2 million, respectively, which was derived from a range of reasonable estimates based upon studies and site surveys. We follow the provisions of AICPA Statement of Position 96-1, which provides key guidance on recognition, measurement and disclosure of remediation liabilities. We have recorded our best estimate of the cost of remediation activities.
          See Item 3 of this annual report for recent developments regarding environmental matters.
     Natural gas imbalances
          In the pipeline transportation business, natural gas imbalances frequently result from differences in gas volumes received from and delivered to our customers. Such differences occur when a customer delivers more or less gas into our pipelines than is physically redelivered back to them during a particular time period. The vast majority of our settlements are through in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an imbalance payable) or received from a customer (in the case of an imbalance receivable). Such in-kind deliveries are on-going and take place over several months. In some cases, settlements of imbalances accumulated over a period of time are ultimately cashed out and are generally negotiated at values which approximate average market prices over a period of time. As a result, for gas imbalances that are ultimately settled over future periods, we estimate the value of such current assets and liabilities using average market prices, which is representative of the estimated value of the imbalances upon final settlement. Changes in natural gas prices may impact our estimates.
          At December 31, 2007 and 2006, our imbalance receivables, net of allowance for doubtful accounts, were $60.9 million and $97.8 million, respectively, and are reflected as a component of “Accounts and notes receivable — trade” on our balance sheets. At December 31, 2007 and 2006, our imbalance payables were $38.3 million and $51.2 million, respectively, and are reflected as a component of “Accrued gas payables” on our balance sheets.
Other Items
     Initial Public Offering of Duncan Energy Partners
          In September 2006, we formed a consolidated subsidiary, Duncan Energy Partners, to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO. On February 5, 2007, Duncan Energy Partners completed its initial public offering of 14,950,000 common units (including an overallotment amount of 1,950,000 common units) at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of $291.9 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of these net proceeds to us along with $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units of Duncan Energy Partners. Duncan Energy Partners used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units it had originally issued to Enterprise Products Partners, resulting in the final amount of 5,351,571 common units beneficially owned by Enterprise Products Partners. We used the cash received from Duncan Energy Partners to temporarily reduce amounts outstanding under EPO’s Multi-Year Revolving Credit Facility.

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      We contributed 66% of our equity interests in the following subsidiaries to Duncan Energy Partners:
 
  §   Mont Belvieu Caverns, which owns salt dome storage caverns located in Mont Belvieu, Texas that receive, store and deliver NGLs and certain petrochemical products for industrial customers located along the upper Texas Gulf Coast, which has the largest concentration of petrochemical plants and refineries in the United States;
 
  §   Acadian Gas, which owns an onshore natural gas pipeline system that gathers, transports, stores and markets natural gas in Louisiana. The Acadian Gas system links natural gas supplies from onshore and offshore Gulf of Mexico developments (including offshore pipelines, continental shelf and deepwater production) with local gas distribution companies, electric generation plants and industrial customers, including those in the Baton Rouge-New Orleans-Mississippi River corridor. A subsidiary of Acadian Gas owns our 49.5% equity interest in Evangeline;
 
  §   Sabine Propylene, which transports polymer-grade propylene between Port Arthur, Texas and a pipeline interconnect located in Cameron Parish, Louisiana;
 
  §   Lou-Tex Propylene, which transports chemical-grade propylene from Sorrento, Louisiana to Mont Belvieu, Texas; and
 
  §   South Texas NGL, which began transporting NGLs from Corpus Christi, Texas to Mont Belvieu, Texas in January 2007. South Texas NGL owns the DEP South Texas NGL Pipeline System.
          In addition to the 34% ownership interest we retained in each of these entities, we also own the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units. Accordingly, we have in effect retained a net economic interest of approximately 52.4% in Duncan Energy Partners as of December 31, 2007. EPO directs the business operations of Duncan Energy Partners through its ownership and control of the general partner of Duncan Energy Partners.
          For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations as a component of our business segments. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners.
          The public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of minority interest in our consolidated financial statements. The public owners of Duncan Energy Partners have no direct equity interests in us as a result of this transaction. The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, we do not have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners. For additional information regarding Duncan Energy Partners, see Note 17 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
           In certain cases, EPO is responsible for funding 100% of project costs rather than sharing such costs with Duncan Energy Partners in accordance with the existing sharing ratio of 66% funded by Duncan Energy Partners and 34% funded by EPO. Under the Omnibus Agreement, EPO agreed to make additional contributions to Duncan Energy Partners as reimbursement for Duncan Energy Partners’ 66% share of any excess project costs above (i) the $28.6 million of estimated project costs to complete the Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated project costs for additional Mont Belvieu brine production capacity and above-ground storage reservoir projects. These projects were in progress at the time of Duncan Energy Partners’ initial public offering. In December 2007, EPO made cash contributions totaling $9.9 million to Duncan Energy Partners’ subsidiaries in connection with the Omnibus Agreement.
           In December 2007, EPO made an additional $38.1 million cash contribution to Mont Belvieu Caverns for capital expenditures in which Duncan Energy Partners is not a participant. This contribution was in accordance with provisions of the Mont Belvieu Caverns’ limited liability company agreement, which states that when Duncan Energy Partners elects to not participate in certain projects, then EPO is responsible for funding 100% of such projects. To the extent such non-participated projects generate incremental earnings for Mont Belvieu Caverns in the future, the sharing ratio for Mont Belvieu Caverns will be adjusted to allocate such incremental cash flows to EPO. Under the terms of the agreement, Duncan Energy Partners may elect to reacquire for consideration a 66% share of these projects at a later date.
Insurance Matters
          We participate as named insureds in EPCO’s current insurance program, which provides us with property damage, business interruption and other coverages, which are customary for the nature and scope of our operations. EPCO attempts to place all insurance coverage with carriers having ratings of “A” or higher. However, two carriers associated with the EPCO insurance program were downgraded by Standard & Poor’s during 2006. One of these carriers is currently rated at “A-” and the other, “BBB.” At present, there is no indication that these two carriers would be unable to fulfill any insuring obligation. Furthermore, we currently do not have any claims which might be affected by these carriers. EPCO continues to monitor these situations. For additional information regarding our significant risks and uncertainties due to hurricanes, see Note 21 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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     Contractual Obligations
          The following table summarizes our significant contractual obligations at December 31, 2007 (dollars in thousands).
                                         
            Payment or Settlement due by Period
            Less than   1-3   3-5   More than
Contractual Obligations   Total   1 year   years   years   5 years
 
Scheduled maturities of long-term debt (1)
  $ 6,896,500     $     $ 1,091,840     $ 1,347,160     $ 4,457,500  
Estimated cash payments for interest (2)
  $ 9,071,523     $ 437,686     $ 831,740     $ 676,622     $ 7,125,475  
Operating lease obligations (3)
  $ 325,705     $ 27,785     $ 49,172     $ 46,922     $ 201,826  
Purchase obligations: (4)
                                       
Product purchase commitments:
                                       
Estimated payment obligations:
                                       
Natural gas
  $ 685,600     $ 137,345     $ 273,940     $ 274,315     $  
NGLs
  $ 4,041,275     $ 697,277     $ 830,264     $ 830,264     $ 1,683,470  
Petrochemicals
  $ 4,065,675     $ 1,751,152     $ 1,261,071     $ 375,368     $ 678,084  
Other
  $ 60,385     $ 31,392     $ 17,114     $ 3,831     $ 8,048  
Underlying major volume commitments:
                                       
Natural gas (in BBtus)
    91,350       18,300       36,500       36,550        
NGLs (in MBbls)
    50,798       9,745       10,172       10,172       20,709  
Petrochemicals (in MBbls)
    45,207       20,115       13,704       4,097       7,291  
Service payment commitments
  $ 8,962     $ 6,745     $ 1,657     $ 186     $ 374  
Capital expenditure commitments (5)
  $ 569,654     $ 569,654     $     $     $  
Other Long-Term Liabilities, as reflected in our Consolidated Balance Sheet (6)
  $ 73,748     $     $ 23,680     $ 3,229     $ 46,839  
             
Total
  $ 25,799,027     $ 3,659,036     $ 4,380,478     $ 3,557,897     $ 14,201,616  
             
 
(1)   Represents our scheduled future maturities of consolidated debt obligations for the periods indicated. See Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding our debt obligations.
 
(2)   Our estimated cash payments for interest are based on the principle amount of consolidated debt obligations outstanding at December 31, 2007. With respect to variable-rate debt, we applied the weighted-average interest rates paid during 2007. See Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding variable interest rates charged in 2007 under our credit agreements. In addition, our estimate of cash payments for interest gives effect to interest rate swap agreements in place at December 31, 2007. See Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. Our estimated cash payments for interest are significantly influenced by the long-term maturities of our $550.0 million Junior Notes A (due August 2066) and $700.0 million Junior Notes B (due January 2068). Our estimated cash payments for interest assume that the Junior Note obligations are not called prior to maturity.
 
(3)   Primarily represents operating leases for (i) underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, (iii) a railcar unloading terminal in Mont Belvieu, Texas and (iv) land held pursuant to right-of-way agreements.
 
(4)   Represents enforceable and legally binding agreements to purchase goods or services based on the contractual terms of each agreement at December 31, 2007.
 
(5)   Represents our short-term unconditional payment obligations relating to our capital projects.
 
(6)   As presented on our Consolidated Balance Sheet at December 31, 2007, other long-term liabilities consist primarily of (i) liabilities for our asset retirement obligations and (ii) liabilities for environmental remediation costs. For information regarding our environmental remediation costs and asset retirement obligations, see Notes 2 and 10 respectively, of our Notes to Consolidated Financial Statements included under Item 8 of this annual report.
          For additional information regarding our significant contractual obligations involving operating leases and purchase obligations, see Note 20 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
     Off-Balance Sheet Arrangements
          Except for the following information regarding debt obligations of certain unconsolidated affiliates, we have no off-balance sheet arrangements, as described in Item 303(a)(4)(ii) of Regulation S-K, that have or are reasonably expected to have a material current or future effect on our financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources. The following information summarizes the significant terms of such unconsolidated debt obligations.

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          Poseidon. At December 31, 2007, Poseidon’s debt obligations consisted of $91.0 million outstanding under its $150.0 million revolving credit facility. Amounts borrowed under this facility mature in May 2011 and are secured by substantially all of Poseidon’s assets.
          Evangeline. At December 31, 2007, Evangeline’s debt obligations consisted of (i) $13.2 million in principal amount of 9.90% fixed rate Series B senior secured notes due December 2010 and (ii) a $7.5 million subordinated note payable. Enterprise Products Partners had $1.1 million of letters of credit outstanding on December 31, 2007 that were furnished on behalf of Evangeline’s debt.
Summary of Related Party Transactions
          The following table summarizes our related party transactions for the periods indicated (dollars in thousands).
                         
    For the Year Ended December 31,
    2007   2006   2005
         
Revenues from consolidated operations
                       
EPCO and affiliates
  $ 362,076     $ 98,671     $ 311  
Unconsolidated affiliates
    290,640       304,559       367,204  
         
Total
  $ 652,716     $ 403,230     $ 367,515  
         
Operating costs and expenses
                       
EPCO and affiliates
  $ 329,699     $ 311,537     $ 293,134  
Unconsolidated affiliates
    32,765       31,606       23,563  
         
Total
  $ 362,464     $ 343,143     $ 316,697  
         
General and administrative expenses
                       
EPCO and affiliates
  $ 56,518     $ 41,265     $ 40,954  
         
          For additional information regarding our related party transactions, see Note 17 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. For information regarding certain business relationships and related transactions, see Item 13 of this annual report.
          We have an extensive and ongoing relationship with EPCO and its affiliates, including TEPPCO and Energy Transfer Equity. Our revenues from EPCO and affiliates are primarily associated with sales of NGL products. Our expenses with EPCO and affiliates are primarily due to (i) reimbursements we pay EPCO in connection with an administrative services agreement and (ii) purchases of NGL products. TEPPCO is an affiliate of ours due to the common control relationship of both entities. Enterprise GP Holdings acquired non-controlling ownership interests in both ETE GP and Energy Transfer Equity in May 2007. As a result of this transaction, ETE GP and Energy Transfer Equity became related parties to us.
          Many of our unconsolidated affiliates perform supporting or complementary roles to our consolidated business operations. The majority of our revenues from unconsolidated affiliates relate to natural gas sales to a Louisiana affiliate. The majority of our expenses with unconsolidated affiliates pertain to payments we make to K/D/S Promix, L.L.C. for NGL transportation, storage and fractionation services.
          On February 5, 2007, our consolidated subsidiary, Duncan Energy Partners, completed an underwritten initial public offering of its common units. Duncan Energy Partners was formed in September 2006 as a Delaware limited partnership to, among other things, acquire ownership interests in certain of our midstream energy businesses. For additional information regarding Duncan Energy Partners, see “Other Items — Initial Public Offering of Duncan Energy Partners” within this section.

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Non-GAAP reconciliations
          A reconciliation of our measurement of total non-GAAP gross operating margin to GAAP operating income and income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles follows (dollars in thousands):
                         
    For the Year the Ended December 31,
    2007   2006   2005
         
Total segment gross operating margin
  $ 1,492,068     $ 1,362,449     $ 1,136,347  
Adjustments to reconcile total gross operating margin
                       
To operating income:
                       
Depreciation, amortization and accretion in operating costs and expenses
    (513,840 )     (440,256 )     (413,441 )
Operating lease expense paid by EPCO
    (2,105 )     (2,109 )     (2,112 )
Gain (loss) on sale of assets in operating costs and expenses
    (5,391 )     3,359       4,488  
General and administrative costs
    (87,695 )     (63,391 )     (62,266 )
         
Consolidated operating income
    883,037       860,052       663,016  
Other expense, net
    (303,463 )     (229,967 )     (225,178 )
         
Income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles
  $ 579,574     $ 630,085     $ 437,838  
         
          EPCO subleases to us certain equipment located at our Mont Belvieu facility and 100 railcars for $1 per year (the “retained leases”). These subleases are part of the administrative services agreement that we executed with EPCO in connection with our formation in 1998. EPCO holds this equipment pursuant to operating leases for which it has retained the corresponding cash lease payment obligation. We record the full value of such lease payments made by EPCO as a non-cash related party operating expense, with the offset to partners’ equity recorded as a general contribution to our partnership. Apart from the partnership interests we granted to EPCO at our formation, EPCO does not receive any additional ownership rights as a result of its contribution to us of the retained leases. For additional information regarding the administrative services agreement and the retained leases, see Item 13 of this annual report.
Cumulative effect of changes in accounting principles
          Our Statements of Consolidated Operations reflect the following cumulative effects of changes in accounting principles:
  §   We recognized, as a benefit, a cumulative effect of a change in accounting principle of $1.5 million in 2006 based on the Statement of Financial Accounting Standards (“SFAS”) 123(R), “Share-Based Payment,” requirements to recognize compensation expense based upon the grant date fair value of an equity award and the application of an estimated forfeiture rate to unvested awards.
 
  §   We recorded a $4.2 million non-cash expense related to certain asset retirement obligations in 2005 due to our implementation of FIN 47 as of December 31, 2005.
          For additional information regarding these changes in accounting principles, including a presentation of the pro forma effects these changes would have had on our historical earnings, see Note 8 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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Recent Accounting Pronouncements
          Several new accounting standards have recently been issued that will or may affect our future financial statements:
  §   Statement of Financial Accounting Standards (“SFAS”) 157, “Fair Value Measurements;”
 
  §   SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51;” and
 
  §   SFAS 141(R), “Business Combinations.”
          For additional information regarding these recent accounting developments and others that may affect our future financial statements, see Note 3 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
          We are exposed to financial market risks, including changes in commodity prices, interest rates and foreign exchange rates. In addition, we are exposed to fluctuations in exchange rates between the U.S. dollar and Canadian dollar. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to (i) the variability of future earnings, (ii) fair values of certain debt instruments and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates.
          We recognize financial instruments as assets and liabilities on our Consolidated Balance Sheets based on fair value. Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.
          Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings. For additional information regarding our accounting for financial instruments, see Note 7 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
          To qualify as a hedge, the item to be hedged must be exposed to commodity, interest rate or exchange rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge is recorded in current earnings.
          We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific hedging criteria. When this occurs, we may enter into a new financial instrument to reestablish the hedge to which the closed instrument relates.

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Interest Rate Risk Hedging Program
          Our interest rate exposure results from variable and fixed rate borrowings under various debt agreements. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. The following information summarizes significant components of our interest rate risk hedging portfolio:
Fair value hedges — Interest rate swaps
          As summarized in the following table, we had eleven interest rate swap agreements outstanding at December 31, 2007 that were accounted for as fair value hedges.
                     
    Number   Period Covered   Termination   Fixed to   Notional
Hedged Fixed Rate Debt   Of Swaps   by Swap   Date of Swap   Variable Rate (1)   Amount
 
Senior Notes B, 7.50% fixed rate, due Feb. 2011
  1   Jan. 2004 to Feb. 2011   Feb. 2011   7.50% to 8.65%   $50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013
  2   Jan. 2004 to Feb. 2013   Feb. 2013   6.38% to 7.19%   $200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014
  6   4th Qtr. 2004 to Oct. 2014   Oct. 2014   5.60% to 6.13%   $600 million
Senior Notes K, 4.95% fixed rate, due June 2010
  2   Aug. 2005 to June 2010   June 2010   4.95% to 5.33%   $200 million
 
     
(1)   The variable rate indicated is the all-in variable rate for the current settlement period.
          We have designated these interest rate swaps as fair value hedges under SFAS 133 since they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in the fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense.
          These eleven agreements have a combined notional amount of $1.1 billion and match the maturity dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a variable interest rate based on six-month London interbank offered rate (“LIBOR”) (plus an applicable margin as defined in each swap agreement), and receive back from the counterparty a fixed interest rate payment based on the stated interest rate of the debt being hedged, with both payments calculated using the notional amounts stated in each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”). The settlement amount is amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.
          The total fair value of these eleven interest rate swaps at December 31, 2007, was an asset of $14.8 million, with an offsetting decrease in the fair value of the underlying debt. Interest expense for the years ended December 31, 2007, 2006 and 2005 reflects a $8.9 million loss, $5.2 million loss and $10.8 million benefit from these swap agreements, respectively.
          The following table shows the effect of hypothetical price movements on the estimated fair value of our interest rate swap portfolio and the related change in fair value (“FV”) of the underlying debt at the dates indicated (dollars in thousands). Income is not affected by changes in the fair value of these swaps; however, these swaps effectively convert the hedged portion of fixed-rate debt to variable-rate debt. As a result, interest expense (and related cash outlays for debt service) will increase or decrease with the change in the periodic “reset” rate associated with the respective swap. Typically, the reset rate is an agreed upon index rate published for the first day of the six-month interest calculation period.
                                 
            Swap Fair Value at
    Resulting   December 31,   December 31,   February 12,
Scenario   Classification   2006   2007   2008
 
FV assuming no change in underlying interest rates
  Asset (Liability)   $ (29,060 )   $ 14,839     $ 42,544  
FV assuming 10% increase in underlying interest rates
  Asset (Liability)     (56,249 )     (5,425 )     24,479  
FV assuming 10% decrease in underlying interest rates
  Asset (Liability)     (1,872 )     35,102       60,610  

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          The fair value of the interest rate swaps excludes related hedged amounts we have recorded in earnings. The change in fair value between December 31, 2007 and February 12, 2008 is primarily due to a decrease in market interest rates relative to the interest rates used to determine the fair value of our financial instruments at December 31, 2007. The underlying floating LIBOR forward interest rate curve used to determine the February 12, 2008 fair values ranged from approximately 2.25% to 5.53% using 6-month reset periods ranging from February 2008 to March 2014.
Cash flow hedges — Interest Rate Swaps
          Duncan Energy Partners had three interest rate swap agreements outstanding at December 31, 2007 that were accounted for as cash flow hedges.
                     
    Number   Period Covered   Termination   Variable to   Notional
Hedged Variable Rate Debt   Of Swaps   by Swap   Date of Swap   Fixed Rate(1)   Value
 
Duncan Energy Partners’ Revolver, due Feb. 2011
  3   Sep. 2007 to Sep. 2010   Sep. 2010   4.84% to 4.62%   $175.0 million
 
(1)   Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).
          In September 2007, Duncan Energy Partners executed three floating-to-fixed interest rate swaps having a combined notional value of $175.0 million. The purpose of these financial instruments is to reduce the sensitivity of Duncan Energy Partners’ earnings to variable interest rates charged under its revolving credit facility. It recognized a $0.2 million benefit from these swaps in interest expense during 2007, which includes ineffectiveness of $0.2 million (an expense) and income of $0.4 million. In 2008, Duncan Energy Partners expects to reclassify $0.7 million of accumulated other comprehensive loss that was generated by these interest rate swaps as an increase to interest expense.
          At December 31, 2007, the aggregate fair value of these interest rate swaps was a liability of $3.8 million. As cash flow hedges, any increase or decrease in fair value (to the extent effective) would be recorded into other comprehensive income and amortized into income based on the settlement period hedged. Any ineffectiveness is recorded directly into earnings as an increase in interest expense. The following table shows the effect of hypothetical price movements on the estimated fair value of Duncan Energy Partners’ interest rate swap portfolio (dollars in thousands).
                         
            Swap Fair Value at
    Resulting   December 31,   February 12,
Scenario   Classification   2007   2008
 
FV assuming no change in underlying interest rates
  Liability   $ 3,782     $ 7,749  
FV assuming 10% increase in underlying interest rates
  Liability     2,245       6,563  
FV assuming 10% decrease in underlying interest rates
  Liability     5,319       8,934  
Cash flow hedges — Treasury locks
          At times, we may use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to our anticipated issuances of debt. A treasury lock is a specialized agreement that fixes the price (or yield) on a specific treasury security for an established period of time. A treasury lock purchaser is protected from a rise in the yield of the underlying treasury security during the lock period. Each of the treasury lock transactions was designated as a cash flow hedge under SFAS 133.
          To the extent effective, gains and losses on the value of the treasury locks will be deferred until the forecasted debt is issued and will be amortized to earnings over the life of the debt. No ineffectiveness was recognized as of December 31, 2007. Gains or losses on the termination of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt.

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          The following table summarizes changes in our treasury lock portfolio since December 31, 2005 (dollars in millions):
                 
    Notional   Cash
    Amount   Gain
     
Second quarter of 2006 additions to portfolio (1)
  $ 250.0     $  
Third quarter of 2006 additions to portfolio (1)
    50.0    
Third quarter of 2006 terminations (2)
    (300.0 )  
Fourth quarter of 2006 additions to portfolio (3)
    562.5    
     
Treasury lock portfolio, December 31, 2006 (4)
    562.5    
     
First quarter of 2007 additions to portfolio (3)
    437.5    
Second quarter of 2007 terminations (5)
    (875.0 )     42.3  
Third quarter of 2007 additions to portfolio (6)
    875.0    
Third quarter of 2007 terminations (7)
    (750.0 )     6.6  
Fourth quarter of 2007 additions to portfolio (8)
    350.0    
     
Treasury lock portfolio, December 31, 2007 (4)
  $ 600.0     $ 48.9  
     
 
(1)   EPO entered into these transactions related to its anticipated issuances of debt in 2006.
 
(2)   Terminations relate to the issuance of the Junior Notes A ($300.0 million).
 
(3)   EPO entered into these transactions related to its anticipated issuances of debt in 2007.
 
(4)   The fair value of open financial instruments at December 31, 2006 and 2007 was an asset of $11.2 million and a liability of $19.6 million, respectively.
 
(5)   Terminations relate to the issuance of the Junior Notes B ($500.0 million) and Senior Notes L ($375.0 million). Of the $42.3 million gain, $10.6 million relates to the Junior Notes B and the remainder to the Senior Notes L and its successor debt.
 
(6)   EPO entered into these transactions related to its issuance of the Senior Notes L (including its successor debt) in August 2007 ($500.0 million) and anticipated issuance of debt during the first half of 2008 ($250.0 million)
 
(7)   Terminations relate to the issuance of the Senior Notes L and its successor debt.
 
(8)   EPO entered into these transactions in anticipated issuance of debt during the first half of 2008.
Commodity Risk Hedging Program
          The prices of natural gas, NGLs and certain petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risks associated with such products, we may enter into commodity financial instruments.
          The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) the value of NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas, NGLs or certain petrochemical products. From time to time, we inject natural gas into storage and utilize hedging instruments to lock in the value of our inventory positions. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.
          The fair value of our commodity financial instrument portfolio, which primarily consisted of cash flow hedges, at December 31, 2007 was a liability of $19.3 million. During the years ended December 31, 2007, 2006 and 2005, we recorded a $28.6 million loss, $10.3 million income and $1.1 million income, respectively, related to our commodity financial instruments, which is included in operating costs and expenses on our Statements of Consolidated Operations. Included in the $28.6 million loss recorded during 2007, was ineffectiveness of $0.9 million (an expense) related to our commodity hedges. These contracts will terminate during 2008, and any amounts remaining in accumulated other comprehensive income will be recorded in earnings.
          We assess the risk of our commodity financial instrument portfolio using a sensitivity analysis model. The sensitivity analysis applied to this portfolio measures the potential income or loss (i.e., the change in fair value of the portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices of the commodity financial instruments outstanding at the date indicated within the following table.

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The following table shows the effect of hypothetical price movements on the estimated fair value of this portfolio at the dates presented (dollars in thousands):
                                 
    Resulting   Commodity Financial Instrument Portfolio FV
Scenario   Classification   December 31,
2006
  December 31,
2007
  February 12,
2008
 
FV assuming no change in underlying commodity prices
  Asset (Liability)   $ (3,184 )   $ (19,305 )   $ 25,941  
FV assuming 10% increase in underlying commodity prices
  Asset (Liability)     (2,119 )     9,903       52,974  
FV assuming 10% decrease in underlying commodity prices
  Liability     (4,249 )     (48,513 )     (1,114 )
          The increase in portfolio fair value between December 31, 2007 and February 12, 2008 is primarily due to an increase in the price of natural gas.
Foreign Currency Hedging Program
          We are exposed to foreign currency exchange rate risk through our Canadian NGL marketing subsidiary and certain construction agreements with respect to our Pioneer processing plant where payments are indexed to the Canadian dollar. As a result, we could be adversely affected by fluctuations in the foreign currency exchange rate between the U.S. dollar and the Canadian dollar. We attempt to hedge this risk using foreign exchange purchase contracts to fix the exchange rate.
          Mark-to-market accounting is utilized for those foreign exchange contracts associated with our Canadian NGL marketing business. The duration of these contracts is typically one month. As of December 31, 2007, $4.7 million of these exchange contracts were outstanding, all of which settled in January 2008. In January 2008, we entered into $3.7 million of such instruments.
          The foreign exchange contracts associated with our construction activities are accounted for using hedge accounting. At December 31, 2007, the fair value of these contracts was $1.3 million. These contracts settle through May 2008.
Product Purchase Commitments
          We have long and short-term purchase commitments for NGLs, petrochemicals and natural gas with several suppliers. The purchase prices that we are obligated to pay under these contracts are based on market prices at the time we take delivery of the volumes. For additional information regarding these commitments, see “Contractual Obligations” included under Item 7 of this annual report.

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Item 8. Financial Statements and Supplementary Data.
ENTERPRISE PRODUCTS PARTNERS L.P.
INDEX TO FINANCIAL STATEMENTS
     
    Page No.
  90
 
   
  91
 
   
  92
 
   
  93
 
   
  94
 
   
  95
 
   
   
  96
  97
  105
  106
  108
  114
  115
  119
  121
  122
  124
  129
  132
  135
  141
  145
  149
  157
  159
  160
  164
  167
  168
  168
  170

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Enterprise Products GP, LLC and
Unitholders of Enterprise Products Partners L.P.
Houston, Texas
          We have audited the accompanying consolidated balance sheets of Enterprise Products Partners L.P. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related statements of consolidated operations, consolidated comprehensive income, consolidated cash flows and consolidated partners’ equity for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
          We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
          In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Enterprise Products Partners L.P. and subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
          We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2008 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2008

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ENTERPRISE PRODUCTS PARTNERS L.P.
CONSOLIDATED BALANCE SHEETS
(Dollars in thousands)
                 
    December 31,
    2007   2006
     
ASSETS
               
Current assets:
               
Cash and cash equivalents
  $ 39,722     $ 22,619  
Restricted cash
    53,144       23,667  
Accounts and notes receivable — trade, net of allowance for doubtful accounts of $21,659 at December 31, 2007 and $23,406 at December 31, 2006
    1,930,762       1,306,290  
Accounts receivable — related parties
    79,782       16,738  
Inventories
    354,282       423,844  
Prepaid and other current assets
    80,193       129,000  
     
Total current assets
    2,537,885       1,922,158  
Property, plant and equipment, net
    11,587,264       9,832,547  
Investments in and advances to unconsolidated affiliates
    858,339       564,559  
Intangible assets, net of accumulated amortization of $341,494 at December 31, 2007 and $251,876 at December 31, 2006
    917,000       1,003,955  
Goodwill
    591,652       590,541  
Deferred tax asset
    3,522       1,855  
Other assets
    112,345       74,103  
     
Total assets
  $ 16,608,007     $ 13,989,718  
     
 
               
LIABILITIES AND PARTNERS’ EQUITY
               
Current liabilities:
               
Accounts payable — trade
  $ 324,999     $ 277,070  
Accounts payable — related parties
    24,432       6,785  
Accrued product payables
    2,227,489       1,364,493  
Accrued expenses
    47,756       35,763  
Accrued interest
    130,971       90,865  
Other current liabilities
    289,036       209,945  
     
Total current liabilities
    3,044,683       1,984,921  
     
Long-term debt: (see Note 14)
               
Senior debt obligations — principal
    5,646,500       4,779,068  
Junior subordinated notes — principal
    1,250,000       550,000  
Other
    9,645       (33,478 )
     
Total long-term debt
    6,906,145       5,295,590  
     
Deferred tax liabilities
    21,364       13,723  
Other long-term liabilities
    73,748       86,121  
Minority interest
    430,418       129,130  
Commitments and contingencies
Partners’ equity:
               
Limited Partners
Common units (433,608,763 units outstanding at December 31, 2007 and 431,303,193 units outstanding at December 31, 2006 )
    5,976,947       6,320,577  
Restricted common units (1,688,540 units outstanding at December 31, 2007 and 1,105,237 units outstanding at December 31, 2006)
    15,948       9,340  
General partner
    122,297       129,175  
Accumulated other comprehensive income
    16,457       21,141  
     
Total partners’ equity
    6,131,649       6,480,233  
     
Total liabilities and partners’ equity
  $ 16,608,007     $ 13,989,718  
     
See Notes to Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED OPERATIONS
(Dollars in thousands, except per unit amounts)
                         
    For Year Ended December 31,
    2007   2006   2005
     
Revenues:
                       
Third parties
  $ 16,297,409     $ 13,587,739     $ 11,889,444  
Related parties
    652,716       403,230       367,515  
     
Total (see Note 16)
    16,950,125       13,990,969       12,256,959  
     
Costs and expenses:
                       
Operating costs and expenses
Third parties
    15,646,587       12,745,948       11,229,528  
Related parties
    362,464       343,143       316,697  
     
Total operating costs and expenses
    16,009,051       13,089,091       11,546,225  
     
General and administrative costs
Third parties
    31,177       22,126       21,312  
Related parties
    56,518       41,265       40,954  
     
Total general and administrative costs
    87,695       63,391       62,266  
     
Total costs and expenses
    16,096,746       13,152,482       11,608,491  
     
Equity in income of unconsolidated affiliates
    29,658       21,565       14,548  
     
Operating income
    883,037       860,052       663,016  
     
Other income (expense):
                       
Interest expense
    (311,764 )     (238,023 )     (230,549 )
Interest income
    8,601       7,589       5,237  
Other, net
    (300 )     467       134  
     
Other expense
    (303,463 )     (229,967 )     (225,178 )
     
Income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles
    579,574       630,085       437,838  
Provision for income taxes
    (15,257 )     (21,323 )     (8,362 )
     
Income before minority interest and the cumulative effect of changes in accounting principles
    564,317       608,762       429,476  
Minority interest
    (30,643 )     (9,079 )     (5,760 )
     
Income before the cumulative effect of changes in accounting principles
    533,674       599,683       423,716  
Cumulative effect of changes in accounting principles (see Note 8)
          1,472       (4,208 )
     
Net income
  $ 533,674     $ 601,155     $ 419,508  
     
 
                       
Net income allocation: (see Note 15)
                       
Limited partners’ interest in net income
  $ 417,728     $ 504,156     $ 348,512  
     
General partner interest in net income
  $ 115,946     $ 96,999     $ 70,996  
     
 
                       
Earnings per unit: (see Note 19)
                       
Basic and diluted income per unit before changes in accounting principles
  $ 0.96     $ 1.22     $ 0.92  
     
Basic and diluted income per unit
  $ 0.96     $ 1.22     $ 0.91  
     
See Notes to Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(Dollars in thousands)
                         
    For Year Ended December 31,
    2007   2006   2005
     
Net income
  $ 533,674     $ 601,155     $ 419,508  
Other comprehensive income:
                       
Cash flow hedges:
                       
Net commodity financial instrument losses during period
    (17,997 )     (3,622 )      
Foreign currency hedge gains
    1,308              
Less: Reclassification adjustment for gain included in net income related to commodity financial instruments
                (1,434 )
Net interest rate financial instrument gains during period
    14,375       11,196        
Less: Amortization of cash flow financing hedges
    (5,429 )     (4,234 )     (4,048 )
     
Total cash flow hedges
    (7,743 )     3,340       (5,482 )
     
Change in funded status of Dixie benefit plans, net of tax
    (52 )          
Foreign currency translation adjustment
    2,007       (807 )      
     
Total other comprehensive income
    (5,788 )     2,533       (5,482 )
     
Comprehensive income
  $ 527,886     $ 603,688     $ 414,026  
     
See Notes to Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in thousands)
                         
    For Year Ended December 31,  
    2007     2006     2005  
     
Operating activities:
                       
Net income
  $ 533,674     $ 601,155     $ 419,508  
Adjustments to reconcile net income to net cash flows provided by operating activities:
                       
Depreciation, amortization and accretion in operating costs and expenses
    513,840       440,256       413,441  
Depreciation and amortization in general and administrative costs
    10,258       7,186       7,184  
Amortization in interest expense
    (336 )     766       152  
Equity in income of unconsolidated affiliates
    (29,658 )     (21,565 )     (14,548 )
Distributions received from unconsolidated affiliates
    73,593       43,032       56,058  
Provision for impairment of long-lived asset
          88        
Cumulative effect of changes in accounting principles
          (1,472 )     4,208  
Operating lease expense paid by EPCO, Inc.
    2,105       2,109       2,112  
Minority interest
    30,643       9,079       5,760  
Loss (gain) on sale of assets
    5,391       (3,359 )     (4,488 )
Deferred income tax expense
    8,306       14,427       8,594  
Changes in fair market value of financial instruments
    981       (51 )     122  
Non-cash pension expense
    588              
Loss on early extinguishment of debt
    250              
Net effect of changes in operating accounts (see Note 22)
    441,306       83,418       (266,395 )
     
Net cash flows provided by operating activities
    1,590,941       1,175,069       631,708  
     
Investing activities:
                       
Capital expenditures
    (2,185,800 )     (1,341,070 )     (864,453 )
Contributions in aid of construction costs
    57,547       60,492       47,004  
Proceeds from sale of assets
    12,027       3,927       44,746  
Decrease (increase) in restricted cash
    (47,347 )     (8,715 )     11,204  
Cash used for business combinations (see Note 12)
    (35,793 )     (276,500 )     (326,602 )
Acquisition of intangible assets
    (11,232 )           (1,750 )
Investments in unconsolidated affiliates
    (332,909 )     (138,266 )     (87,342 )
Advances from (to) unconsolidated affiliates
    (10,100 )     10,844       (702 )
Return of investment from unconsolidated affiliate
                47,500  
     
Cash used in investing activities
    (2,553,607 )     (1,689,288 )     (1,130,395 )
     
Financing activities:
                       
Borrowings under debt agreements
    6,024,518       3,378,285       4,192,345  
Repayments of debt
    (4,458,141 )     (2,907,000 )     (3,630,611 )
Debt issuance costs
    (16,511 )     (8,955 )     (9,297 )
Distributions paid to partners
    (957,705 )     (843,292 )     (716,699 )
Distributions paid to minority interests
    (32,326 )     (8,831 )     (5,724 )
Contributions from Duncan Energy Partners reflected as part of minority interests (see Notes 2 and 17)
    290,466              
Other contributions from minority interests
    12,506       27,578       39,110  
Contributions from general partner related to issuance of restricted units
                177  
Net proceeds from issuance of common units
    69,221       857,187       646,928  
Repurchase of restricted units and options
    (1,568 )            
Settlement of treasury lock contracts
    48,895              
     
Cash provided by financing activities
    979,355       494,972       516,229  
     
Effect of exchange rate changes on cash
    414       (232 )      
Net change in cash and cash equivalents
    16,689       (19,247 )     17,542  
Cash and cash equivalents, January 1
    22,619       42,098       24,556  
     
Cash and cash equivalents, December 31
  $ 39,722     $ 22,619     $ 42,098  
     
See Notes to Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.
STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY
(See Note 15 for Unit History and Detail of Changes in Limited Partners’ Equity)
(Dollars in thousands)
                                                 
    Limited   General   Treasury   Deferred        
    Partners   Partner   units   Comp.   AOCI   Total
     
Balance, December 31, 2004
  $ 5,217,267     $ 106,475     $ (8,660 )   $ (10,851 )   $ 24,554     $ 5,328,785  
Net income
    348,512       70,996                         419,508  
Operating leases paid by EPCO, Inc.
    2,070       42                         2,112  
Cash distributions to partners
    (630,560 )     (76,752 )                       (707,312 )
Unit option reimbursements to EPCO, Inc.
    (9,199 )     (188 )                       (9,387 )
Net proceeds from sales of common units
    612,616       12,502                         625,118  
Proceeds from exercise of unit options
    21,374       436                         21,810  
Issuance of restricted units
    9,478       177             (9,480 )           175  
Forfeiture of restricted units
    (2,663 )     (38 )           2,361             (340 )
Amortization of Employee Partnership awards
    1,358       28                         1,386  
Amortization of deferred compensation
                      3,373             3,373  
Cancellation of treasury units
    (8,915 )     (182 )     8,660                   (437 )
Cash flow hedges
                            (5,482 )     (5,482 )
     
Balance, December 31, 2005
    5,561,338       113,496             (14,597 )     19,072       5,679,309  
Net income
    504,156       96,999                         601,155  
Operating leases paid by EPCO, Inc.
    2,067       42                         2,109  
Cash distributions to partners
    (739,632 )     (101,805 )                       (841,437 )
Unit option reimbursements to EPCO, Inc.
    (1,818 )     (41 )                       (1,859 )
Net proceeds from sales of common units
    830,825       16,943                         847,768  
Common units issued to Lewis in connection with Encinal acquisition
    181,112       3,705                         184,817  
Proceeds from exercise of unit options
    5,601       114                         5,715  
Change in accounting method for equity awards (see Note 8)
    (15,815 )     (307 )           14,597             (1,525 )
Change in funded status of pension and postretirement plans, net of tax
                            (464 )     (464 )
Amortization of equity awards
    8,282       155                         8,437  
Foreign currency translation adjustment
                            (807 )     (807 )
Acquisition-related disbursement of cash (see Note 15)
    (6,199 )     (126 )                       (6,325 )
Cash flow hedges
                            3,340       3,340  
     
Balance, December 31, 2006
    6,329,917       129,175                   21,141       6,480,233  
Net income
    417,728       115,946                         533,674  
Operating leases paid by EPCO, Inc.
    2,063       42                         2,105  
Cash distributions to partners
    (833,793 )     (124,388 )                       (958,181 )
Unit option reimbursements to EPCO, Inc.
    (2,999 )     (58 )                       (3,057 )
Net proceeds from sales of common units
    60,445       1,232                         61,677  
Proceeds from exercise of unit options
    7,549       154                         7,703  
Repurchase of restricted units and options
    (1,568 )                             (1,568 )
Change in funded status of pension and postretirement plans, net of tax
                            1,052       1,052  
Amortization of equity awards
    13,553       194                         13,747  
Foreign currency translation adjustment
                            2,007       2,007  
Cash flow hedges
                            (7,743 )     (7,743 )
     
Balance, December 31, 2007
  $ 5,992,895     $ 122,297     $     $     $ 16,457     $ 6,131,649  
     
See Notes to Consolidated Financial Statements.

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ENTERPRISE PRODUCTS PARTNERS L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
          Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.
Note 1. Partnership Organization
          Enterprise Products Partners L.P. 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 “EPD.” 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.
          We were formed in April 1998 to own and operate certain natural gas liquids (“NGLs”) related businesses of EPCO, Inc. (“EPCO”). We conduct substantially all of our business through our wholly owned subsidiary, Enterprise Products Operating LLC (“EPO”), as successor in interest by merger to Enterprise Products Operating L.P. We are owned 98% by our limited partners and 2% by Enterprise Products GP, LLC (our general partner, referred to as “EPGP”). EPGP is owned 100% by Enterprise GP Holdings L.P. (“Enterprise GP Holdings”), a publicly traded affiliate, the units of which are listed on the NYSE under the ticker symbol “EPE.” The general partner of Enterprise GP Holdings is EPE Holdings, LLC (“EPE Holdings”), a wholly owned subsidiary of Dan Duncan LLC, the membership interests of which are owned by Dan L. Duncan. We, EPGP, Enterprise GP Holdings, EPE Holdings and Dan Duncan LLC are affiliates and under common control of Dan L. Duncan, the Group Co-Chairman and controlling shareholder of EPCO.
          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. References to “LE GP” mean LE GP, LLC, which is the general partner of Energy Transfer Equity. 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 for information regarding the formation of Enterprise Unit L.P. in February 2008.
          On February 5, 2007, a consolidated subsidiary of ours, Duncan Energy Partners L.P. (“Duncan Energy Partners”), completed an initial public offering of its common units (see Note 17). Duncan Energy Partners owns equity interests in certain of our midstream energy businesses. References to “DEP GP” mean DEP Holdings, LLC, which is the general partner of Duncan Energy Partners and is wholly owned by EPO.
          For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments. We control Duncan Energy Partners through our ownership of its general partner. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners. Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of minority interest in our consolidated financial statements. The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, we do not have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.

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Note 2. Summary of Significant Accounting Policies
     Allowance for Doubtful Accounts
          Our allowance for doubtful accounts is determined based on specific identification and estimates of future uncollectible accounts. Our procedure for determining the allowance for doubtful accounts is based on (i) historical experience with customers, (ii) the perceived financial stability of customers based on our research, and (iii) the levels of credit we grant to customers. In addition, we may increase the allowance account in response to the specific identification of customers involved in bankruptcy proceedings and similar financial difficulties. On a routine basis, we review estimates associated with the allowance for doubtful accounts to ensure that we have recorded sufficient reserves to cover potential losses. Our allowance also includes estimates for uncollectible natural gas imbalances based on specific identification of accounts.
          The following table presents the activity of our allowance for doubtful accounts for the years ended December 31, 2007, 2006 and 2005:
                         
    For the Years Ended December 31,
    2007   2006   2005
     
Balance at beginning of period
  $ 23,406     $ 37,329     $ 32,773  
Charges to expense
    2,614       473       5,391  
Acquisition-related additions and other
                5,541  
Deductions
    (4,361 )     (14,396 )     (6,376 )
     
Balance at end of period
  $ 21,659     $ 23,406     $ 37,329  
     
     Cash and Cash Equivalents
          Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of less than three months from the date of purchase.
          Our Statements of Consolidated Cash Flows are prepared using the indirect method. The indirect method derives net cash flows from operating activities by adjusting net income to remove (i) the effects of all deferrals of past operating cash receipts and payments, such as changes during the period in inventory, deferred income and similar transactions, (ii) the effects of all accruals of expected future operating cash receipts and cash payments, such as changes during the period in receivables and payables, (iii) the effects of all items classified as investing or financing cash flows, such as gains or losses on sale of property, plant and equipment or extinguishment of debt, and (iv) other non-cash amounts such as depreciation, amortization and changes in the fair market value of financial instruments.
     Consolidation Policy
          We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own. Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling interest, after the elimination of all material intercompany accounts and transactions. We also consolidate other entities and ventures in which we possess a controlling financial interest as well as partnership interests where we are the sole general partner of the partnership.
          If the entity is organized as a limited partnership or limited liability company and maintains separate ownership accounts, we account for our investment using the equity method if our ownership interest is between 3% and 50% and we exercise significant influence over the entity’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20% and 50% and we exercise significant influence over the entity’s operating and financial policies. Our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates are eliminated in consolidation to the extent such amounts are material

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and remain on our balance sheet (or those of our equity method investments) in inventory or similar accounts.
          If our ownership interest in an entity does not provide us with either control or significant influence, we account for the investment using the cost method.
     Contingencies
          Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. Our management and its legal counsel assess such contingent liabilities, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
          If the assessment of a contingency indicates that it is probable that a material loss has been incurred and the amount of liability can be estimated, then the estimated liability would be accrued in our financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss (if determinable and material), is disclosed.
          Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed.
     Current Assets and Current Liabilities
          We present, as individual captions in our consolidated balance sheets, all components of current assets and current liabilities that exceed five percent of total current assets and liabilities, respectively.
     Deferred Revenues
          We recognize revenues when earned (see Note 4). Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue.
     Earnings Per Unit
          Earnings per unit is based on the amount of income allocated to limited partners and the weighted-average number of units outstanding during the period. See Note 19 for additional information regarding our earnings per unit.
     Employee Benefit Plans
          In 2005, we acquired a controlling ownership interest in Dixie Pipeline Company (“Dixie”), which resulted in Dixie becoming a consolidated subsidiary of ours. Dixie employs the personnel that operate its pipeline system and certain of these employees are eligible to participate in a defined contribution plan and pension and postretirement benefit plans.
          Statement of Financial Accounting Standards (“SFAS”) 158, "Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R),” requires businesses to record the over-funded or under-funded status of defined benefit pension and other postretirement plans as an asset or liability at a measurement date and to recognize annual changes in the funded status of each plan through other comprehensive income. At December 31, 2006, Dixie adopted the provisions of SFAS 158. See Note 6 for additional information regarding Dixie’s employee benefit plans.

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     Environmental Costs
          Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies, and regulatory approvals. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. Expenditures to mitigate or prevent future environmental contamination are capitalized.
          Environmental costs and related accruals were not significant prior to the GulfTerra Merger. As a result of the merger, we assumed an environmental liability for remediation costs associated with mercury gas meters. The balance of this environmental liability was $17.2 million and $20.3 million at December 31, 2007 and 2006, respectively. At December 31, 2007 and 2006, total reserves for environmental liabilities, including those related to the mercury gas meters, were $26.5 million and $24.2 million, respectively. At December 31, 2007 and 2006, $6.3 million and $7.1 million, respectively, of these amounts are classified as current liabilities.
          In February 2007, we reserved $6.5 million in cash we received from a third party to fund anticipated future environmental remediation costs. These expected costs are associated with assets acquired in connection with the GulfTerra Merger. Previously, the third party had been obligated to indemnify us for such costs. As a result of the settlement, this indemnification arrangement was terminated.
          The following table presents the activity of our environmental reserves for the years ended December 31, 2007, 2006 and 2005:
                         
    For the Years Ended December 31,
    2007   2006   2005
     
Balance at beginning of period
  $ 24,178     $ 22,090     $ 22,119  
Charges to expense
    375       1,105       139  
Acquisition-related additions and other
    6,499       8,811        
Deductions
    (4,593 )     (7,828 )     (168 )
     
Balance at end of period
  $ 26,459     $ 24,178     $ 22,090  
     
     Estimates
          Preparing our consolidated financial statements in conformity with generally accepted accounting principles in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Our actual results could differ from these estimates. On an ongoing basis, management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.
     Exchange Contracts
          Exchanges are contractual agreements for the movements of natural gas liquids (“NGLs”) and certain petrochemical products between parties to satisfy timing and logistical needs of the parties. Net exchange volumes borrowed from us under such agreements are valued and included in accounts receivable, and net exchange volumes loaned to us under such agreements are valued and accrued as a liability in accrued product payables.

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          Receivables and payables arising from exchange transactions are settled with movements of products rather than with cash. When payment or receipt of monetary consideration is required for product differentials and service costs, such items are recognized in our consolidated financial statements on a net basis.
     Exit and Disposal Costs
          Exit and disposal costs are charges associated with an exit activity not associated with a business combination or with a disposal activity covered by SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Examples of these costs include (i) termination benefits provided to current employees that are involuntarily terminated under the terms of a benefit arrangement that, in substance, is not an ongoing benefit arrangement or an individual deferred compensation contract, (ii) costs to terminate a contract that is not a capital lease, and (iii) costs to consolidate facilities or relocate employees. In accordance with SFAS 146, “Accounting for Costs Associated with Exit and Disposal Activities,” we recognize such costs when they are incurred rather than at the date of our commitment to an exit or disposal plan.
     Financial Instruments
          We use financial instruments such as swaps, forward and other contracts to manage price risks associated with inventories, firm commitments, interest rates, foreign currency and certain anticipated transactions. We recognize these transactions on our balance sheet as assets and liabilities based on the instrument’s fair value. Fair value is generally defined as the amount at which the financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale.
          Changes in fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instrument meets the criteria of a fair value hedge, gains and losses incurred on the instrument will be recorded in earnings to offset corresponding losses and gains on the hedged item. If the financial instrument meets the criteria of a cash flow hedge, gains and losses incurred on the instrument are recorded in accumulated other comprehensive income (“AOCI”). Gains and losses on cash flow hedges are reclassified from accumulated other comprehensive income to earnings when the forecasted transaction occurs or, as appropriate, over the economic life of the underlying asset. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.
          To qualify as a hedge, the item to be hedged must expose us to risk and the related hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at its inception and thereafter on a quarterly basis. Any hedge ineffectiveness is immediately recognized in earnings. See Note 7 for additional information regarding our financial instruments.
     Foreign Currency Translation
          We own a NGL marketing business located in Canada. The financial statements of this foreign subsidiary are translated into U.S. dollars from the Canadian dollar, which is the subsidiary’s functional currency, using the current rate method. Its assets and liabilities are translated at the rate of exchange in effect at the balance sheet date, while revenue and expense items are translated at average rates of exchange during the reporting period. Exchange gains and losses arising from foreign currency translation adjustments are reflected as separate components of accumulated other comprehensive income in the accompanying Consolidated Balance Sheets. Our net cash flows from this Canadian subsidiary may be adversely affected by changes in foreign currency exchange rates. We attempt to hedge this currency risk (see Note 7).

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     Impairment Testing for Goodwill
          Our goodwill amounts are assessed for impairment (i) on a routine annual basis or (ii) when impairment indicators are present. If such indicators occur (e.g., the loss of a significant customer, economic obsolescence of plant assets, etc.), the estimated fair value of the reporting unit to which the goodwill is assigned is determined and compared to its book value. If the fair value of the reporting unit exceeds its book value including associated goodwill amounts, the goodwill is considered to be unimpaired and no impairment charge is required. If the fair value of the reporting unit is less than its book value including associated goodwill amounts, a charge to earnings is recorded to reduce the carrying value of the goodwill to its implied fair value. We have not recognized any impairment losses related to goodwill for any of the periods presented. See Note 13 for additional information regarding our goodwill.
     Impairment Testing for Long-Lived Assets
          Long-lived assets (including intangible assets with finite useful lives and property, plant and equipment) are reviewed for impairment when events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable.
          Long-lived assets with carrying values that are not expected to be recovered through future cash flows are written-down to their estimated fair values in accordance with SFAS 144. The carrying value of a long-lived asset is deemed not recoverable if it exceeds the sum of undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset carrying value exceeds the sum of its undiscounted cash flows, a non-cash asset impairment charge equal to the excess of the asset’s carrying value over its estimated fair value is recorded. Fair value is defined as the amount at which an asset or liability could be bought or settled in an arm’s-length transaction. We measure fair value using market price indicators or, in the absence of such data, appropriate valuation techniques.
          We recorded a non-cash asset impairment charge of $0.1 million in 2006, which is reflected as a component of operating costs and expenses in our 2006 Statement of Consolidated Operations. No asset impairment charges were recorded in 2007 and 2005.
     Impairment Testing for Unconsolidated Affiliates
          We evaluate our equity method investments for impairment when events or changes in circumstances indicate that there is a loss in value of the investment attributable to an other than temporary decline. Examples of such events or changes in circumstances include continuing operating losses of the entity and/or long-term negative changes in the entity’s industry. In the event we determine that the loss in value of an investment is other than a temporary decline, we record a charge to earnings to adjust the carrying value of the investment to its estimated fair value.
          During 2007, we evaluated our equity method investment in Nemo Gathering Company, LLC for impairment. As a result of this evaluation, we recorded a $7.0 million non-cash impairment charge that is a component of equity income from unconsolidated affiliates for the year ended December 31, 2007. Similarly, during 2006, we evaluated our investment in Neptune Pipeline Company, L.L.C. (“Neptune”) for impairment. As a result of this evaluation, we recorded a $7.4 million non-cash impairment charge that is a component of equity income from unconsolidated affiliates for the year ended December 31, 2006. We had no such impairment charges during the year ended December 31, 2005. See Note 11 for additional information regarding our equity method investments.
     Income Taxes
          Provision for income taxes is primarily applicable to our state tax obligations under the Revised Texas Franchise Tax (“the Revised Texas Franchise Tax”) and certain federal and state tax obligations of Seminole Pipeline Company (“Seminole”) and Dixie, both of which are consolidated subsidiaries of ours. Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes.

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          In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax. In May 2006, the State of Texas expanded its pre-existing franchise tax to include limited partnerships, limited liability companies, corporations and limited liability partnerships. As a result of the change in tax law, our tax status in the State of Texas has changed from non-taxable to taxable.
          Since we are structured as a pass-through entity, we are not subject to federal income taxes. As a result, our partners are individually responsible for paying federal income taxes on their share of our taxable income. Since we do not have access to information regarding each partner’s tax basis, we cannot readily determine the total difference in the basis of our net assets for financial and tax reporting purposes.
          In accordance with Financial Accounting Standards Board Interpretation (“FIN”) 48, “Accounting for Uncertainty in Income Taxes,” we must recognize the tax effects of any uncertain tax positions we may adopt, if the position taken by us is more likely than not sustainable. If a tax position meets such criteria, the tax effect to be recognized by us would be the largest amount of benefit with more than a 50% chance of being realized upon settlement. This guidance was effective January 1, 2007, and our adoption of this guidance had no material impact on our financial position, results of operations or cash flows. See Note 18 for additional information regarding our income taxes.
     Inventories
          Inventories primarily consist of NGLs, certain petrochemical products and natural gas volumes that are valued at the lower of average cost or market. We capitalize, as a cost of inventory, shipping and handling charges directly related to volumes we purchase from third parties or take title to in connection with processing or other agreements. As these volumes are sold and delivered out of inventory, the average cost of these products (including freight-in charges that have been capitalized) are charged to operating costs and expenses. Shipping and handling fees associated with products we sell and deliver to customers are charged to operating costs and expenses as incurred. See Note 9 for additional information regarding our inventories.
     Minority Interest
          As presented in our Consolidated Balance Sheets, minority interest represents third-party ownership interests in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our majority owned subsidiaries are consolidated with those of our own, with any third-party ownership in such amounts presented as minority interest. Effective February 1, 2007, the public owners of Duncan Energy Partners’ common units are presented as a minority interest in our consolidated financial statements.
          Minority interest, as reflected on our December 31, 2007 balance sheet, consists of $288.6 million attributable to third party owners of Duncan Energy Partners and the remainder to our other consolidated affiliates.
          Minority interest expense for the year ended December 31, 2007 includes $13.9 million attributable to third party owners of Duncan Energy Partners. The remaining minority interest expense amounts for 2007 and likewise those for 2006 are attributable to our other consolidated affiliates.
          Contributions from minority interests for the year ended December 31, 2007 includes $290.5 million received from third parties in connection with the initial public offering of Duncan Energy Partners in February 2007.
     Natural Gas Imbalances
          In the natural gas pipeline transportation business, imbalances frequently result from differences in natural gas volumes received from and delivered to our customers. Such differences occur when a customer delivers more or less gas into our pipelines than is physically redelivered back to them during a particular time period. We have various fee-based agreements with customers to transport their natural gas through

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our pipelines. Our customers retain ownership of their natural gas shipped through our pipelines. As such, our pipeline transportation activities are not intended to create physical volume differences that would result in significant accounting or economic events for either our customers or us during the course of the arrangement.
          We settle pipeline gas imbalances through either (i) physical delivery of in-kind gas or (ii) in cash. These settlements follow contractual guidelines or common industry practices. As imbalances occur, they may be settled (i) on a monthly basis, (ii) at the end of the agreement or (iii) in accordance with industry practice, including negotiated settlements. Certain of our natural gas pipelines have a regulated tariff rate mechanism requiring customer imbalance settlements each month at current market prices.
          However, the vast majority of our settlements are through in-kind arrangements whereby incremental volumes are delivered to a customer (in the case of an imbalance payable) or received from a customer (in the case of an imbalance receivable). Such in-kind deliveries are on-going and take place over several periods. In some cases, settlements of imbalances built up over a period of time are ultimately cashed out and are generally negotiated at values which approximate average market prices over a period of time. For those gas imbalances that are ultimately settled over future periods, we estimate the value of such current assets and liabilities using average market prices, which is representative of the estimated value of the imbalances upon final settlement. Changes in natural gas prices may impact our estimates.
          At December 31, 2007 and 2006, our natural gas imbalance receivables, net of allowance for doubtful accounts, were $60.9 million and $97.8 million, respectively, and are reflected as a component of “Accounts and notes receivable — trade” on our Consolidated Balance Sheets. At December 31, 2007 and 2006, our imbalance payables were $38.3 million and $51.2 million, respectively, and are reflected as a component of “Accrued product payables” on our Consolidated Balance Sheets.
     Property, Plant and Equipment
          Property, plant and equipment is recorded at cost. Expenditures for additions, improvements and other enhancements to property, plant and equipment are capitalized and minor replacements, maintenance, and repairs that do not extend asset life or add value are charged to expense as incurred. When property, plant and equipment assets are retired or otherwise disposed of, the related cost and accumulated depreciation is removed from the accounts and any resulting gain or loss is included in the results of operations for the respective period. For financial statement purposes, depreciation is recorded based on the estimated useful lives of the related assets primarily using the straight-line method. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes. See Note 10 for additional information regarding our property, plant and equipment.
          Certain of our plant operations entail periodic planned outages for major maintenance activities. These planned shutdowns typically result in significant expenditures, which are principally comprised of amounts paid to third parties for materials, contract services and related items. We use the expense-as-incurred method for our planned major maintenance activities that benefit periods in excess of one year or for periods that are not determinable. We use the deferral method for our annual planned major maintenance activities.
          Asset retirement obligations (“AROs”) are legal obligations associated with the retirement of tangible long-lived assets that result from their acquisition, construction, development and/or normal operation. When an ARO is incurred, we record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related long-lived asset. Over time, the liability is accreted to its present value (accretion expense) and the capitalized amount is depreciated over the remaining useful life of the related long-lived asset. To the extent we do not settle an ARO liability at our recorded amounts, we will incur a gain or loss.

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     Reclassifications
          A reclassification was made to the Statements of Operations for the year ended December 31, 2005 to consistently reflect our 2005 revenues due to a reclassification of $12.7 million from “Third-parties” to “Related-parties” attributable to our Onshore Natural Gas Pipelines & Services business segment. Such reclassification related to the presentation of our 49.5% equity method investment in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp. (collectively “Evangeline”) which revised its disclosures. A reclassification was made to the Statements of Consolidated Comprehensive Income for the year ended December 31, 2006 to include $2.2 million in reclassification adjustments for losses included in net income related to financial instruments and $8.7 million in net interest rate financial instrument gains to conform to the current year presentation of such activities.
     Restricted Cash
          Restricted cash represents amounts held by (i) a brokerage firm in connection with our commodity financial instruments portfolio and physical natural gas purchases made on the New York Mercantile Exchange (“NYMEX”) exchange, and (ii) us for the future settlement of current liabilities we assumed in connection with our acquisition of a Canadian affiliate in October 2006.
     Revenue Recognition
          See Note 4 for information regarding our revenue recognition policies.
     Start-Up and Organization Costs
          Start-up costs and organization costs are expensed as incurred. Start-up costs are defined as one-time activities related to opening a new facility, introducing a new product or service, conducting activities in a new territory, pursuing a new class of customer, initiating a new process in an existing facility, or some new operation. Routine ongoing efforts to improve existing facilities, products or services are not considered start-up costs. Organization costs include legal fees, promotional costs and similar charges incurred in connection with the formation of a business.
     Unit-Based Awards
          We account for unit-based awards in accordance with SFAS 123(R), “Share-Based Payment.” Prior to January 1, 2006, our unit-based awards were accounted for using the intrinsic value method described in Accounting Principles Board Opinion (“APB”) 25, “Accounting for Stock Issued to Employees.” The following table discloses the pro forma effect of unit-based compensation amounts on our net income and earnings per unit for the year ended December 31, 2005 as if we had applied the provisions of SFAS 123(R) instead of APB 25. The effects of applying SFAS 123(R) in the following pro forma disclosures may not be indicative of future amounts as additional awards in future years are anticipated. No pro forma adjustments are required for restricted unit awards in 2005 since compensation expense related to these awards was based on their estimated fair values. See Note 5 for additional information regarding our unit-based awards.
         
Reported net income
  $ 419,508  
Additional unit option-based compensation expense estimated using fair value-based method
    (708 )
Reduction in compensation expense related to Employee Partnership equity awards
    1,271  
 
     
Pro forma net income
  $ 420,071  
 
     
 
       
Basic and diluted earnings per unit:
       
As reported
  $ 0.91  
 
     
Pro forma
  $ 0.91  
 
     

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Note 3. Recent Accounting Developments
          The following information summarizes recently issued accounting guidance that will or may affect our future financial statements:
     SFAS 157
          SFAS 157, “Fair Value Measurements,” defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 applies only to fair-value measurements that are already required (or permitted) by other accounting standards and is expected to increase the consistency of those measurements. SFAS 157 emphasizes that fair value is a market-based measurement that should be determined based on the assumptions that market participants would use in pricing an asset or liability. Companies will be required to disclose the extent to which fair value is used to measure assets and liabilities, the inputs used to develop such measurements, and the effect of certain of the measurements on earnings (or changes in net assets) during a period.
          Certain requirements of SFAS 157 are effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The effective date for other requirements of SFAS 157 has been deferred for one year. We adopted the provisions of SFAS 157 which are effective for fiscal years beginning after November 15, 2007 and there was no impact on our financial statements. Management is currently evaluating the impact that the deferred provisions of SFAS 157 will have on the disclosures in our financial statements in 2009.
     SFAS 141(R)
          SFAS 141(R), “Business Combinations,” replaces SFAS 141, “Business Combinations.” SFAS 141(R) retains the fundamental requirements of SFAS 141 that the acquisition method of accounting (previously termed the “purchase method”) be used for all business combinations and for an acquirer to be identified for each business combination. SFAS 141(R) defines the acquirer as the entity that obtains control of one or more businesses in a business combination and establishes the acquisition date as the date that the acquirer achieves control. This new guidance also retains guidance in SFAS 141 for identifying and recognizing intangible assets separately from goodwill.
          The objective of SFAS 141(R) is to improve the relevance, representational faithfulness, and comparability of the information a reporting entity provides in its financial reports about business combinations and their effects. To accomplish this, SFAS 141(R) establishes principles and requirements for how the acquirer:
  §   Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interests in the acquiree.
 
  §   Recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase. SFAS 141(R) defines a bargain purchase as a business combination in which the total acquisition-date fair value of the identifiable net assets acquired exceeds the fair value of the consideration transferred plus any noncontrolling interest in the acquiree, and requires the acquirer to recognize that excess in earnings as a gain attributable to the acquirer.
 
  §   Determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination.
          SFAS 141(R) also requires that direct costs of an acquisition (e.g. finder’s fees, outside consultants, etc.) be expensed as incurred and not capitalized as part of the purchase price.
          As a calendar year-end entity, we will adopt SFAS 141(R) on January 1, 2009. Although we are still evaluating this new guidance, we expect that it will have an impact on the way in which we evaluate acquisitions. For example, we have made several acquisitions in the past where the fair value of assets

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acquired and liabilities assumed was in excess of the purchase price. In those cases, a bargain purchase would have been recognized under SFAS 141(R). Conversely, we will no longer capitalize transaction fees and other direct costs.
     SFAS 160
          SFAS 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51,” establishes accounting and reporting standards for non-controlling interests, which have been referred to as minority interests in prior accounting literature. A noncontrolling interest is the portion of equity in a subsidiary not attributable, directly or indirectly, to a parent company. This new standard requires, among other things, that (i) ownership interests of noncontrolling interests be presented as a component of equity on the balance sheet (i.e. elimination of the mezzanine “minority interest” category); (ii) elimination of minority interest expense as a line item on the statement of income and, as a result, that net income be allocated between the parent and noncontrolling interests on the face of the statement of income; and (iii) enhanced disclosures regarding noncontrolling interests. As a calendar year-end entity, we will adopt SFAS 160 on January 1, 2009 and apply its presentation and disclosure requirements retrospectively.
Note 4. Revenue Recognition
          In general, we recognize revenue from our customers when all of the following criteria are met: (i) persuasive evidence of an exchange arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the buyer’s price is fixed or determinable and (iv) collectability is reasonably assured. The following information provides a general description our underlying revenue recognition policies by business segment:
     NGL Pipelines & Services
          This aspect of our business generates revenues primarily from the provision of natural gas processing, NGL pipeline transportation, product storage and NGL fractionation services and the sale of NGLs. 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 (i.e. mixed percent-of-liquids and fee-based) and keepwhole contracts. Under margin-band and keepwhole contracts, we take ownership of mixed NGLs extracted from the producer’s natural gas stream and recognize revenue when the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. In the same way, revenue is recognized under our percent-of-liquids contracts except that the volume of NGLs we extract and sell is less than the total amount of NGLs extracted from the producers’ natural gas. Under a percent-of-liquids contract, the producer retains title to the remaining percentage of mixed NGLs we extract. Under a percent-of-proceeds contract, we share in the proceeds generated from the sale of the mixed NGLs we extract on the producer’s behalf. If a cash fee for natural gas processing services is stipulated by the contract, we record revenue when the natural gas has been processed and delivered to the producer.
          Our NGL marketing activities generate revenues from the sale of NGLs obtained from either our natural gas processing activities or purchased from third parties on the open market. Revenues from these sales contracts are recognized when the NGLs are delivered to customers. In general, the sales prices referenced in these contracts are market-related and can include pricing differentials for such factors as delivery location.
          Under our NGL pipeline transportation contracts and tariffs, revenue is recognized when volumes have been delivered to customers. Revenue from these contracts and tariffs is generally based upon a fixed fee per gallon of liquids transported multiplied by the volume delivered. Transportation fees charged under these arrangements are either contractual or regulated by governmental agencies such as the Federal Energy Regulatory Commission (“FERC”).

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          We collect storage revenues under our NGL and related product storage contracts based on the number of days a customer has volumes in storage multiplied by a storage rate (as defined in each contract). Under these contracts, revenue is recognized ratably over the length of the storage period. With respect to capacity reservation agreements, we collect a fee for reserving storage capacity for customers in our underground storage wells. Under these agreements, revenue is recognized ratably over the specified reservation period. Excess storage fees are collected when customers exceed their reservation amounts and are recognized in the period of occurrence.
          Revenues from product terminalling activities (applicable to our import and export operations) are recorded in the period such services are provided. Customers are typically billed a fee per unit of volume loaded or unloaded. With respect to export operations, revenues may also include demand payments charged to customers who reserve the use of our export facilities and later fail to use them. Demand fee revenues are recognized when the customer fails to utilize the specified export facility as required by contract.
          We enter into fee-based arrangements and percent-of-liquids contracts for the NGL fractionation services we provide to customers. Under such fee-based arrangements, revenue is recognized in the period services are provided. Such fee-based arrangements typically include a base-processing fee (typically in cents per gallon) that is subject to adjustment for changes in certain fractionation expenses (e.g. natural gas fuel costs). Certain of our NGL fractionation facilities generate revenues using percent-of-liquids contracts. Such contracts allow us to retain a contractually determined percentage of the customer’s fractionated NGL products as payment for services rendered. Revenue is recognized from such arrangements when we sell and deliver the retained NGLs to customers.
     Onshore Natural Gas Pipelines & Services
          This aspect of our business generates revenues primarily from the provision of natural gas pipeline transportation and gathering services; natural gas storage services; and from the sale of natural gas. Certain of our onshore natural gas pipelines generate revenues from transportation and gathering agreements as customers are billed a fee per unit of volume multiplied by the volume delivered or gathered. Fees charged under these arrangements are either contractual or regulated by governmental agencies such as the FERC. Revenues associated with these fee-based contracts are recognized when volumes have been delivered.
          Revenues from natural gas storage contracts typically have two components: (i) a monthly demand payment, which is associated with storage capacity reservations, and (ii) a storage fee per unit of volume held at each location. Revenues from demand payments are recognized during the period the customer reserves capacity. Revenues from storage fees are recognized in the period the services are provided.
          Our natural gas marketing activities generate revenues from the sale of natural gas purchased from third parties on the open market. Revenues from these sales contracts are recognized when the natural gas is delivered to customers. In general, the sales prices referenced in these contracts are market-related and can include pricing differentials for such factors as delivery location.
     Offshore Pipelines & Services
          This aspect of our business generates revenues from the provision of offshore natural gas and crude oil pipeline transportation services and related offshore platform operations. Our offshore natural gas pipelines generate revenues through fee-based contracts or tariffs where revenues are equal to the product of a fee per unit of volume (typically in MMBtus) multiplied by the volume of natural gas transported. Revenues associated with these fee-based contracts and tariffs are recognized when natural gas volumes have been delivered.
          The majority of our revenues from offshore crude oil pipelines are derived from purchase and sale arrangements whereby crude oil is purchased from shippers at various receipt points along the pipeline for an index-based price (less a price differential) and sold back to the shippers at various redelivery points at the same index-based price. Net revenue recognized from such arrangements is based on the price

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differential per unit of volume (typically in barrels) multiplied by the volume delivered. In addition, certain offshore crude oil pipelines generate revenues based upon a gathering fee per unit of volume (typically in barrels) multiplied by the volume delivered to the customer. Revenues from both arrangements are recognized when the crude oil is delivered.
          Revenues from offshore platform services generally consist of demand payments and commodity charges. Revenues from platform services are recognized in the period the services are provided. 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.
     Petrochemical Services
          This aspect of our business generates revenues from the provision of isomerization and propylene fractionation services and the sale of certain petrochemical products. Our isomerization and propylene fractionation operations generate revenues through fee-based arrangements, which 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. Revenues resulting from such agreements are recognized in the period the services are provided.
          Our petrochemical marketing activities generate revenues from the sale of propylene and other petrochemicals obtained from either its processing activities or purchased from third parties on the open market. Revenues from these sales contracts are recognized when the petrochemicals are delivered to customers. In general, the sales prices referenced in these contracts are market-related and can include pricing differentials for such factors as delivery location.
Note 5. Accounting for Unit-Based Awards
          Since January 1, 2006, we account for unit-based awards in accordance with SFAS 123(R) (see Note 2). The following table summarizes our unit-based compensation amounts by plan during each of the periods indicated:
                         
    For the Years Ended December 31,  
    2007     2006     2005  
     
EPCO 1998 Long-Term Incentive Plan (“1998 Plan”)
                       
Unit options
  $ 4,447     $ 701     $  
Restricted units
    7,721       5,019       3,776  
     
Total 1998 Plan (1)
    12,168       5,720       3,776  
     
Employee Partnerships
    3,911       2,146       2,043  
DEP Holdings, LLC Unit Appreciation Rights
    69              
     
Total consolidated expense
  $ 16,148     $ 7,866     $ 5,819  
     
 
(1)   Amounts for the year ended December 31, 2007 include $4.6 million associated with the resignation of our former chief executive officer.
          See Note 25 for information regarding the formation of the Enterprise Products 2008 Long-Term Incentive Plan in January 2008 and Enterprise Unit L.P. in February 2008.
          SFAS 123(R) requires us to recognize compensation expense related to unit-based awards based on the fair value of the award at grant date. The fair value of restricted unit awards (i.e. time-vested units under SFAS 123(R)) is based on the market price of the underlying common units on the date of grant. The fair value of other unit-based awards is estimated using the Black-Scholes option pricing model. Under

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SFAS 123(R), the fair value of an equity-classified award (such as a restricted unit award) is amortized to earnings on a straight-line basis over the requisite service or vesting period. Compensation expense for liability-classified awards (such as unit appreciation rights (“UARs”)) is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. Liability-type awards are cash settled upon vesting.
          As used in the context of the EPCO plans, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires.
          Upon our adoption of SFAS 123(R), we recognized, as a benefit, a cumulative effect of a change in accounting principle of $1.5 million based on the SFAS 123(R) requirement to recognize compensation expense based upon the grant date fair value of an equity award and the application of an estimated forfeiture rate to unvested awards. In addition, previously recognized deferred compensation expense of $14.6 million related to our restricted common units was reversed on January 1, 2006.
          Prior to our adoption of SFAS 123(R), we did not recognize any compensation expense related to unit options; however, compensation expense was recognized in connection with awards granted by EPE Unit L.P. (“EPE Unit I”) and the issuance of restricted units. The effects of applying SFAS 123(R) during the year ended December 31, 2006 did not have a material effect on our net income or basic and diluted earnings per unit. Since we adopted SFAS 123(R) using the modified prospective method, we have not restated the financial statements of prior periods to reflect this new standard.
     1998 Plan
          Unit option awards. Under the 1998 Plan, non-qualified incentive options to purchase a fixed number of our common units may be granted to EPCO’s key employees who perform management, administrative or operational functions for us. When issued, the exercise price of each option grant is equivalent to the market price of the underlying equity on the date of grant. In general, options granted under the 1998 Plan have a cliff vesting period of four years and remain exercisable for ten years from the date of grant.
          In order to fund its obligations under the 1998 Plan, EPCO may purchase common units at fair value either in the open market or directly from us. When employees exercise unit options, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.
          The fair value of each unit option is estimated on the date of grant using the Black-Scholes option pricing model, which incorporates various assumptions including expected life of the options, risk-free interest rates, expected distribution yield on our common units, and expected unit price volatility of our common units. In general, our assumption of expected life of the options represents the period of time that the options are expected to be outstanding based on an analysis of historical option activity. Our selection of the risk-free interest rate is based on published yields for U.S. government securities with comparable terms. The expected distribution yield and unit price volatility is estimated based on several factors, which include an analysis of our historical unit price volatility and distribution yield over a period equal to the expected life of the option.
          The 1998 Plan provides for the issuance of up to 7,000,000 of our common units. After giving effect to outstanding option awards at December 31, 2007 and the issuance and forfeiture of restricted unit awards through December 31, 2007, a total of 1,282,256 additional common units could be issued under the 1998 Plan.

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     The following table presents option activity under the 1998 Plan for the periods indicated:
                                 
                    Weighted-    
            Weighted-   average    
            average   remaining   Aggregate
    Number of   strike price   contractual   Intrinsic
    Units   (dollars/unit)   term (in years)   Value (1)
     
Outstanding at December 31, 2004
    2,463,000     $ 18.84                  
Granted (2)
    530,000       26.49                  
Exercised
    (826,000 )     14.77                  
Forfeited
    (85,000 )     24.73                  
 
                               
Outstanding at December 31, 2005
    2,082,000       22.16                  
Granted (3)
    590,000       24.85                  
Exercised
    (211,000 )     15.95                  
Forfeited
    (45,000 )     24.28                  
 
                               
Outstanding at December 31, 2006
    2,416,000       23.32                  
Granted (4)
    895,000       30.63                  
Exercised
    (256,000 )     19.26                  
Settled or forfeited (5)
    (740,000 )     24.62                  
 
                               
Outstanding at December 31, 2007 (6)
    2,315,000       26.18       7.73     $ 3,291  
                     
Options exercisable at:
                               
December 31, 2005
    727,000     $ 19.19       5.54     $ 3,503  
     
December 31, 2006
    591,000     $ 20.85       5.11     $ 4,808  
     
December 31, 2007 (6)
    335,000     $ 22.06       3.96     $ 3,291  
     
 
(1)   Aggregate intrinsic value reflects fully vested unit options at the date indicated.
 
(2)   The total grant date fair value of these awards was $0.7 million based on the following assumptions: (i) weighted-average expected life of options of seven years; (ii) weighted-average risk-free interest rate of 4.2%; (iii) weighted-average expected distribution yield on our common units of 9.2%; and (iv) weighted-average expected unit price volatility on our common units of 20.0%.
 
(3)   The total grant date fair value of these awards was $1.2 million based on the following assumptions: (i) weighted-average expected life of options of seven years; (ii) weighted-average risk-free interest rate of 5.0%; (iii) weighted-average expected distribution yield on our common units of 8.9%; and (iv) weighted-average expected unit price volatility on our common units of 23.5%.
 
(4)   The total grant date fair value of these awards was $2.4 million based on the following assumptions: (i) expected life of options of seven years; (ii) weighted-average risk-free interest rate of 4.8%; (iii) weighted-average expected distribution yield on our common units of 8.4%; and (iv) weighted-average expected unit price volatility on our common units of 23.2%.
 
(5)   Includes the settlement of 710,000 options in connection with the resignation of our former chief executive officer.
 
(6)   We were committed to issue 2,315,000 and 2,416,000 of our common units at December 31, 2007 and 2006, respectively, if all outstanding options awarded under the 1998 Plan (as of these dates) were exercised. An additional 285,000, 380,000, 510,000 and 805,000 of these options are exercisable in 2008, 2009, 2010 and 2011, respectively.
          The total intrinsic value of option awards exercised during the years ended December 31, 2007, 2006 and 2005 were $3.0 million, $2.2 million and $9.2 million, respectively. At December 31, 2007, there was an estimated $2.8 million of total unrecognized compensation cost related to nonvested option awards granted under the 1998 Plan. We expect to recognize this amount over a weighted-average period of 3.0 years. We will recognize our share of these costs in accordance with the EPCO administrative services agreement (see Note 17).
          During the years ended December 31, 2007 and 2006, we received cash of $7.5 million and $5.6 million, respectively from the exercise of option awards granted under the 1998 Plan. Conversely, our option-related reimbursements to EPCO were $3.0 million and $1.8 million, respectively.

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          Restricted unit awards. Under the 1998 Plan, we may also issue restricted common units to key employees of EPCO and directors of our general partner. In general, the restricted unit awards allow recipients to acquire the underlying common units at no cost to the recipient once a defined cliff vesting period expires, subject to certain forfeiture provisions. The restrictions on such units generally lapse four years from the date of grant. Compensation expense is recognized on a straight-line basis over the vesting period. Fair value of such restricted units is based on the market price of the underlying common units on the date of grant and an allowance for estimated forfeitures.
           Each recipient is also entitled to cash distributions equal to the product of the number of restricted units outstanding for the participant and the cash distribution per unit paid by us to our unitholders. Since restricted units are issued securities, such distributions are reflected as a component of cash distributions to partners as shown on our statements of consolidated cash flows. We paid $2.6 million, $1.6 million and $0.9 million in cash distributions with respect to restricted units during the years ended December 31, 2007, 2006 and 2005, respectively.
           The following table summarizes information regarding our restricted unit awards for the periods indicated:
                 
            Weighted-
            Average Grant
    Number of   Date Fair Value
    Units   per Unit(1)
     
Restricted units at December 31, 2004
    488,525          
Granted (2)
    362,011     $ 26.43  
Vested
    (6,484 )   $ 22.00  
Forfeited
    (92,448 )   $ 24.03  
 
               
Restricted units at December 31, 2005
    751,604          
Granted (3)
    466,400     $ 25.21  
Vested
    (42,136 )   $ 24.02  
Forfeited
    (70,631 )   $ 22.86  
 
               
Restricted units at December 31, 2006
    1,105,237          
Granted (4)
    738,040     $ 25.61  
Vested
    (4,884 )   $ 25.28  
Forfeited
    (36,800 )   $ 23.51  
Settled (5)
    (113,053 )   $ 23.24  
 
               
Restricted units at December 31, 2007
    1,688,540          
 
               
 
(1)   Determined by dividing the aggregate grant date fair value of awards (including an allowance for forfeitures) by the number of awards issued.
 
(2)   Aggregate grant date fair value of restricted unit awards issued during 2005 was $8.8 million based on grant date market prices of our common units ranging from $25.83 to $26.95 per unit and an estimated forfeiture rate of 8.2%.
 
(3)   Aggregate grant date fair value of restricted unit awards issued during 2006 was $10.8 million based on grant date market prices of our common units ranging from $24.85 to $27.45 per unit and estimated forfeiture rates ranging from 7.8% to 9.8%.
 
(4)   Aggregate grant date fair value of restricted unit awards issued during 2007 was $18.9 million based on grant date market prices of our common units ranging from $28.00 to $31.83 per unit and estimated forfeiture rates ranging from 4.6% to 17.0%.
 
(5)   Reflects the settlement of restricted units in connection with the resignation of our former chief executive officer.
          The total fair value of restricted units that vested during the year ended December 31, 2007 was $0.1 million. At December 31, 2007, there was an estimated $25.5 million of total unrecognized compensation cost related to restricted unit awards granted under the 1998 Plan, which we expect to recognize over a weighted-average period of 2.4 years. We will recognize our share of such costs in accordance with the EPCO administrative services agreement.
           Phantom unit awards. The 1998 Plan also provides for the issuance of phantom unit awards. These liability awards are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at redemption dates in each award. The fair market value of each phantom unit award is equal to the market closing price of our common units on the redemption date. Each participant is required to redeem their phantom units as they vest, which typically is four years from the date the award is granted. No phantom unit awards have been issued to date under the 1998 Plan.
           The 1998 Plan also provides for the award of distribution equivalent rights (“DERs”) in tandem with its phantom unit awards. A DER entitles the participant to cash distributions equal to the product of the number of phantom units outstanding for the participant and the cash distribution rate paid by us to our unitholders.
     Employee Partnerships
          EPCO formed the Employee Partnerships to serve as an incentive arrangement for key employees of EPCO by providing them a “profits interest” in the Employee Partnerships. Certain EPCO employees who work on behalf of us and EPCO were issued Class B limited partner interests and admitted as Class B limited partners without any capital contribution. The profits interest awards (i.e., the Class B limited partner interests) in the Employee Partnerships entitles each holder to participate in the appreciation in value of Enterprise GP Holdings’ Units. The Class B limited partner interests are subject to forfeiture if the participating employee’s employment with EPCO is terminated prior to vesting, with customary exceptions for death, disability and certain retirements. The risk of forfeiture will also lapse upon certain change in control events.
          Prior to our adoption of SFAS 123(R), the estimated value of these awards was accounted for in a manner similar to a stock appreciation right. Starting January 1, 2006, compensation expense attributable to these awards was based on the estimated grant date fair value of each award. A portion of the fair value of these equity-based awards is allocated to us under the EPCO administrative services agreement as a non-cash expense. We are not responsible for reimbursing EPCO for any expenses of the Employee

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Partnerships, including the value of any contributions of cash or units of Enterprise GP Holdings made by private company affiliates of EPCO at the formation of each Employee Partnership.
          Currently, there are four Employee Partnerships. EPE Unit I was formed in August 2005 in connection with Enterprise GP Holdings’ initial public offering. EPE Unit II was formed in December 2006. EPE Unit III was formed in May 2007.
          At December 31, 2007, there was an estimated $26.9 million of combined unrecognized compensation cost related to the Employee Partnerships. We will recognize our share of these costs in accordance with the EPCO administrative services agreement over a weighted-average period of 3.9 years.
          The following is a discussion of significant terms of EPE Unit I, EPE Unit II, and EPE Unit III.
          EPE Unit I. In connection with the initial public offering of Enterprise GP Holdings in August 2005, EPE Unit I was formed to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in EPE Unit I. In August 2005, EPE Unit I used $51.0 million in contributions it received from its Class A limited partner (an affiliate of EPCO) to purchase 1,821,428 units of Enterprise GP Holdings. Certain EPCO employees, including all of EPGP’s executive officers other than Dan L. Duncan and Dr. Ralph S. Cunningham, were admitted as Class B limited partners of EPE Unit I without any capital contributions.
          Unless otherwise agreed to by EPCO, the Class A limited partner and a majority of the Class B limited partners, EPE Unit I will be liquidated upon the earlier of (i) August 2010 or (ii) a change in control of Enterprise GP Holdings or its general partner, EPE Holdings. Upon liquidation of EPE Unit I, units having a fair market value equal to the Class A limited partner’s capital base, plus any Class A preferred return for the quarter in which liquidation occurs, will be distributed to the Class A limited partner. Any remaining units will be distributed to the Class B limited partners as a residual profits interest award in EPE Unit I.
          As adjusted for forfeitures and regrants, the grant date fair value of the Class B limited partnership interests in EPE Unit I was $12.2 million at December 31, 2007. This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards ranging from three to five years, (ii) risk-free interest rates ranging from 4.1% to 5.0%, (iii) an expected distribution yield on units of Enterprise GP Holdings ranging from 3.0% to 4.2%, and (iv) an expected unit price volatility for Enterprise GP Holdings’ units ranging from 17.4% to 30.0%.
          EPE Unit II. In December 2006, EPE Unit II, L.P. was formed to serve as an incentive arrangement for Dr. Ralph S. Cunningham, an executive officer of our general partner. The officer, who is not a participant in EPE Unit I, was granted a “profits interest” award in EPE Unit II. EPCO serves as the general partner of EPE Unit II.
          At inception, EPE Unit II used $1.5 million in contributions it received from an affiliate of EPCO (which was admitted as the Class A limited partner of EPE Unit II as a result of such contribution) to purchase 40,725 units of Enterprise GP Holdings at an average price of $36.91 per unit in December 2006. The officer was issued a Class B limited partner interest in EPE Unit II without any capital contribution.
          Unless otherwise agreed upon by EPCO, the Class A limited partner and the Class B limited partner, EPE Unit II will be liquidated upon the earlier of (i) December 2011 or (ii) a change in control of Enterprise GP Holdings or its general partner, EPE Holdings. Upon liquidation of the EPE Unit II, units having a fair market value equal to the Class A limited partner’s capital base will be distributed to the Class A limited partner, plus any Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partner as a residual profits interest award in EPE Unit II.

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          The grant date fair value of the Class B limited partnership interests in EPE Unit II was $0.2 million at December 31, 2007. This fair value was estimated on the date of grant using the Black-Scholes option pricing model, which incorporated various assumptions including (i) an expected life of the award of five years, (ii) risk-free interest rate of 4.4%, (iii) an expected distribution yield on units of Enterprise GP Holdings of 3.8%, and (iv) an expected Enterprise GP Holdings unit price volatility of 18.7%.
          EPE Unit III. EPE Unit III owns 4,421,326 units of Enterprise GP Holdings contributed to it by a private company affiliate of EPCO, which, in turn, was made the Class A limited partner of EPE Unit III. The units of Enterprise GP Holdings contributed by the Class A limited partner had a fair value of $170.0 million on the date of contribution (the “Class A limited partner capital base”). Certain EPCO employees were issued Class B limited partner interests and admitted as Class B limited partners of EPE Unit III without any capital contribution. The profits interest awards (i.e., Class B limited partner interests) in EPE Unit III entitle the holder to participate in the appreciation in value of Enterprise GP Holdings’ units owned by EPE Unit III.
          Unless otherwise agreed to by EPCO, the Class A limited partner and a majority in interest of the Class B limited partners of EPE Unit III, EPE Unit III will be liquidated upon the earlier of: (i) May 7, 2012 or (ii) a change in control of Enterprise GP Holdings or its general partner. EPE Unit III has the following material terms regarding its quarterly cash distribution to partners:
  §   Distributions of Cash flow - Each quarter, 100% of the cash distributions received by EPE Unit III from Enterprise GP Holdings will be distributed to the Class A limited partner until it has received an amount equal to the pro rata Class A preferred return (as defined below), and any remaining distributions received by EPE Unit III will be distributed to the Class B limited partners. The Class A preferred return equals 3.797% per annum, of the Class A limited partner’s capital base. The Class A limited partner’s capital base equals approximately $170.0 million plus any unpaid Class A preferred return from prior periods, less any distributions made by EPE Unit III of proceeds from the sale of Enterprise GP Holdings’ units owned by EPE Unit III (as described below).
 
  §   Liquidating Distributions - Upon liquidation of EPE Unit III, Enterprise GP Holdings’ units having a fair market value equal to the Class A limited partner capital base will be distributed to a private company affiliate of EPCO, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining units of Enterprise GP Holdings will be distributed to the Class B limited partners.
 
  §   Sale Proceeds - If EPE Unit III sells any of the 4,421,326 units of Enterprise GP Holdings that it owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above.
          The Class B limited partner interests in EPE Unit III that are owned by EPCO employees are subject to forfeiture if the participating employee’s employment with EPCO and its affiliates is terminated prior to May 7, 2012, with customary exceptions for death, disability and certain retirements. The risk of forfeiture associated with the Class B limited partner interests in EPE Unit III will also lapse upon certain change of control events.
          As adjusted for forfeitures and regrants, the grant date fair value of the Class B limited partnership interests in EPE Unit III was $23.0 million at December 31, 2007. This fair value was estimated using the Black-Scholes option pricing model, which incorporates various assumptions including (i) an expected life of the awards ranging from four to five years, (ii) risk-free interest rates ranging from 3.5% to 4.9%, (iii) an expected distribution yield on units of Enterprise GP Holdings ranging from 4.0% to 4.3%, and (iv) an expected unit price volatility for Enterprise GP Holdings’ units ranging from 16.9% to 17.6%.

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     DEP Holdings, LLC Unit Appreciation Rights
          The non-employee directors of DEP Holdings, LLC, the general partner of Duncan Energy Partners (“DEP GP”), have been granted UARs in the form of letter agreements. These liability awards are not part of any established long-term incentive plan of EPCO, Enterprise GP Holdings or us. The compensation expense associated with these awards is recognized by DEP GP, which is our consolidated subsidiary. The UARs entitle each non-employee director to receive a cash payment on the vesting date equal to the excess, if any, of the fair market value of Enterprise GP Holdings’ units (determined as of a future vesting date) over the grant date fair value. If a director resigns prior to vesting, his UAR awards are forfeited. These UARs are accounted for similar to liability awards under SFAS 123(R) since they will be settled with cash.
          As of December 31, 2007, a total of 90,000 UARs had been granted to non-employee directors of DEP GP that cliff vest in 2012. If a director resigns prior to vesting, his UAR awards are forfeited. The grant date fair value with respect to these UARs is based on an Enterprise GP Holdings’ unit price of $36.68.
Note 6. Employee Benefit Plans
          Dixie employs the personnel that operate its pipeline system and certain of these employees are eligible to participate in a defined contribution plan and pension and postretirement benefit plans. Due to the immaterial nature of Dixie’s employee benefit plans to our consolidated financial position, results of operations and cash flows, our discussion is limited to the following:
     Defined Contribution Plan
          Dixie contributed $0.3 million to its company-sponsored defined contribution plan for each of the years ended December 31, 2007 and 2006.
     Pension and Postretirement Benefit Plans
          Dixie’s pension plan is a noncontributory defined benefit plan that provides for the payment of benefits to retirees based on their age at retirement, years of service and average compensation. Dixie’s postretirement benefit plan also provides medical and life insurance to retired employees. The medical plan is contributory and the life insurance plan is noncontributory. Dixie employees hired after July 1, 2004 are not eligible for pension and other benefit plans after retirement.
          The following table presents Dixie’s benefit obligations, fair value of plan assets and funded status at December 31, 2007.
                         
    Pension   Postretirement        
    Plan   Plan        
     
Projected benefit obligation
  $ 7,250     $ 5,882          
Accumulated benefit obligation
    4,971                
Fair value of plan assets
    5,572                
Unfunded liability
    1,678       5,882          
Funded status (liability)
    1,678       5,882          
          Projected benefit obligations and net periodic benefit costs are based on actuarial estimates and assumptions. The weighted-average actuarial assumptions used in determining the projected benefit obligation at December 31, 2007 were as follows: discount rate of 5.75%; rate of compensation increase of 4.00% and 5.00% for the pension and postretirement plans, respectively; and a medical trend rate of 8.00% for 2008 grading to an ultimate trend of 5.00% for 2010 and later years. Dixie’s net pension and postretirement benefit costs for 2007 were $1.1 million (including settlement loss of $0.6 million) and $0.4 million, respectively. Dixie’s net pension and postretirement benefit costs for 2006 were $0.7 million and $0.3 million, respectively.

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          Future benefits expected to be paid from Dixie’s pension and postretirement plans are as follows for the periods indicated:
                         
    Pension   Postretirement        
    Plan   Plan        
     
2008
  $ 218     $ 389          
2009
    287       422          
2010
    324       467          
2011
    518       505          
2012
    534       497          
2013 through 2017
    3,779       2,353          
     
Total
  $ 5,660     $ 4,633          
     
          On December 31, 2006, Dixie adopted the recognition and disclosure provisions of SFAS 158. Dixie uses a December 31 measurement date of these plans. SFAS 158 requires Dixie to recognize the funded status of its defined benefit pension and other postretirement plans as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income.
          The incremental effects of Dixie’s implementation of SFAS 158 on our Consolidated Balance Sheets at December 31, 2006 are presented in the following table.
                         
    At December 31, 2006
    Prior to   Effect of    
    Adopting   Adopting    
    SFAS 158   SFAS 158   As reported
 
Liability for Dixie benefit plans
  $ 6,404     $ 751     $ 7,155  
Deferred income taxes
          (287 )     (287 )
Total liabilities
    7,509,021       464       7,509,485  
Accumulated other comprehensive income
          (464 )     (464 )
Total equity
    6,480,697       (464 )     6,480,233  
          Included in Accumulated Other Comprehensive Income (“AOCI”) on the Consolidated Balance Sheet at December 31, 2007 and 2006 are the following amounts that have not been recognized in net periodic pension costs (in millions):
                 
    At December 31,
    2007   2006
     
Unrecognized transition obligation
  $ 1.0     $ 1.2  
Net of tax
    0.6       0.7  
 
               
Unrecognized prior service cost credit
    (1.2 )     (1.5 )
Net of tax
    (0.8 )     (0.9 )
 
               
Unrecognized net actuarial loss
    2.8       3.1  
Net of tax
    1.7       1.9  
Note 7. Financial Instruments
          We are exposed to financial market risks, including changes in commodity prices, interest rates and foreign exchange rates. In addition, we are exposed to fluctuations in exchange rates between the U.S. dollar and Canadian dollar. We may use financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the type of risks we attempt to hedge are those related to (i) the variability of future earnings, (ii) fair values of certain debt instruments and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates.

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          We recognize financial instruments as assets and liabilities on our Consolidated Balance Sheets based on fair value. Fair value is generally defined as the amount at which a financial instrument could be exchanged in a current transaction between willing parties, not in a forced or liquidation sale. The estimated fair values of our financial instruments have been determined using available market information and appropriate valuation techniques. We must use considerable judgment, however, in interpreting market data and developing these estimates. Accordingly, our fair value estimates are not necessarily indicative of the amounts that we could realize upon disposition of these instruments. The use of different market assumptions and/or estimation techniques could have a material effect on our estimates of fair value.
          Changes in the fair value of financial instrument contracts are recognized currently in earnings unless specific hedge accounting criteria are met. If the financial instruments meet those criteria, the instrument’s gains and losses offset the related results of the hedged item in earnings for a fair value hedge and are deferred in other comprehensive income for a cash flow hedge. Gains and losses related to a cash flow hedge are reclassified into earnings when the forecasted transaction affects earnings. For additional information regarding our accounting for financial instruments, see Note 2 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
          To qualify as a hedge, the item to be hedged must be exposed to commodity, interest rate or exchange rate risk and the hedging instrument must reduce the exposure and meet the hedging requirements of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities” (as amended and interpreted). We must formally designate the financial instrument as a hedge and document and assess the effectiveness of the hedge at inception and on a quarterly basis. Any ineffectiveness of the hedge is recorded in current earnings.
          We routinely review our outstanding financial instruments in light of current market conditions. If market conditions warrant, some financial instruments may be closed out in advance of their contractual settlement dates thus realizing income or loss depending on the specific hedging criteria. When this occurs, we may enter into a new financial instrument to reestablish the hedge to which the closed instrument relates.
Interest Rate Risk Hedging Program
          Our interest rate exposure results from variable and fixed rate borrowings under various debt agreements. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar arrangements, which allow us to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. The following information summarizes significant components of our interest rate risk hedging portfolio:
     Fair value hedges – Interest rate swaps
          As summarized in the following table, we had eleven interest rate swap agreements outstanding at December 31, 2007 that were accounted for as fair value hedges.
                                         
    Number   Period Covered   Termination   Fixed to   Notional
Hedged Fixed Rate Debt   Of Swaps   by Swap   Date of Swap   Variable Rate (1)   Amount
 
Senior Notes B, 7.50% fixed rate, due Feb. 2011
    1     Jan. 2004 to Feb. 2011   Feb. 2011   7.50% to 8.65%   $50 million
Senior Notes C, 6.375% fixed rate, due Feb. 2013
    2     Jan. 2004 to Feb. 2013   Feb. 2013   6.38% to 7.19%   $200 million
Senior Notes G, 5.6% fixed rate, due Oct. 2014
    6     4th Qtr. 2004 to Oct. 2014   Oct. 2014   5.60% to 6.13%   $600 million
Senior Notes K, 4.95% fixed rate, due June 2010
    2     Aug. 2005 to June 2010   June 2010   4.95% to 5.33%   $200 million
 
(1)   The variable rate indicated is the all-in variable rate for the current settlement period.
          We have designated these eleven interest rate swaps as fair value hedges under SFAS 133 since they mitigate changes in the fair value of the underlying fixed rate debt. As effective fair value hedges, an increase in the fair value of these interest rate swaps is equally offset by an increase in the fair value of the underlying hedged debt. The offsetting changes in fair value have no effect on current period interest expense.

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          These eleven agreements have a combined notional amount of $1.1 billion and match the maturity dates of the underlying debt being hedged. Under each swap agreement, we pay the counterparty a variable interest rate based on six-month London interbank offered rate (“LIBOR”) (plus an applicable margin as defined in each swap agreement), and receive back from the counterparty a fixed interest rate payment based on the stated interest rate of the debt being hedged, with both payments calculated using the notional amounts stated in each swap agreement. We settle amounts receivable from or payable to the counterparties every six months (the “settlement period”). The settlement amount is amortized ratably to earnings as either an increase or a decrease in interest expense over the settlement period.
          The total fair value of these eleven interest rate swaps at December 31, 2007, was an asset of $14.8 million, with an offsetting decrease in the fair value of the underlying debt. Interest expense for the years ended December 31, 2007, 2006 and 2005 reflects a $8.9 million loss, $5.2 million loss and $10.8 million benefit from these swap agreements, respectively.
     Cash flow hedges – Interest Rate Swaps
          Duncan Energy Partners had three interest rate swap agreements outstanding at December 31, 2007 that were accounted for as cash flow hedges.
                     
    Number   Period Covered   Termination   Variable to   Notional
Hedged Variable Rate Debt   Of Swaps   by Swap   Date of Swap   Fixed Rate(1)   Value
 
Duncan Energy Partners’ Revolver, due Feb. 2011
  3   Sep. 2007 to Sep. 2010   Sep. 2010   4.84% to 4.62%   $175.0 million
 
(1)   Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).
          In September 2007, Duncan Energy Partners executed three floating-to-fixed interest rate swaps having a combined notional value of $175.0 million. The purpose of these financial instruments is to reduce the sensitivity of Duncan Energy Partners’ earnings to variable interest rates charged under its revolving credit facility. It recognized a $0.2 million benefit from these swaps in interest expense during 2007, which includes ineffectiveness of $0.2 million (an expense) and income of $0.4 million. In 2008, Duncan Energy Partners expects to reclassify $0.7 million of accumulated other comprehensive loss that was generated by these interest rate swaps as an increase to interest expense.
     At December 31, 2007, the aggregate fair value of these interest rate swaps was a liability of $3.8 million. As cash flow hedges, any increase or decrease in fair value (to the extent effective) would be recorded into other comprehensive income and amortized into income based on the settlement period hedged. Any ineffectiveness is recorded directly into earnings as an increase in interest expense.
     Cash flow hedges – Treasury locks
          At times, we may use treasury lock financial instruments to hedge the underlying U.S. treasury rates related to our anticipated issuances of debt. A treasury lock is a specialized agreement that fixes the price (or yield) on a specific treasury security for an established period of time. A treasury lock purchaser is protected from a rise in the yield of the underlying treasury security during the lock period. Each of the treasury lock transactions was designated as a cash flow hedge under SFAS 133.

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          To the extent effective, gains and losses on the value of the treasury locks will be deferred until the forecasted debt is issued and will be amortized to earnings over the life of the debt. No ineffectiveness was recognized as of December 31, 2007. Gains or losses on the termination of such instruments are amortized to earnings using the effective interest method over the estimated term of the underlying fixed-rate debt. The following table summarizes changes in our treasury lock portfolio since December 31, 2005 (dollars in millions):
                 
    Notional   Cash
    Amount   Gain
     
Second quarter of 2006 additions to portfolio (1)
  $ 250.0     $  
Third quarter of 2006 additions to portfolio (1)
    50.0        
Third quarter of 2006 terminations (2)
    (300.0 )      
Fourth quarter of 2006 additions to portfolio (3)
    562.5        
     
Treasury lock portfolio, December 31, 2006 (4)
    562.5        
     
First quarter of 2007 additions to portfolio (3)
    437.5        
Second quarter of 2007 terminations (5)
    (875.0 )     42.3  
Third quarter of 2007 additions to portfolio (6)
    875.0        
Third quarter of 2007 terminations (7)
    (750.0 )     6.6  
Fourth quarter of 2007 additions to portfolio (8)
    350.0        
     
Treasury lock portfolio, December 31, 2007 (4)
  $ 600.0     $ 48.9  
     
 
(1)   EPO entered into these transactions related to its anticipated issuances of debt in 2006.
 
(2)   Terminations relate to the issuance of the Junior Notes A ($300.0 million).
 
(3)   EPO entered into these transactions related to its anticipated issuances of debt in 2007.
 
(4)   The fair value of open financial instruments at December 31, 2006 and 2007 was an asset of $11.2 million and a liability of $19.6 million, respectively.
 
(5)   Terminations relate to the issuance of the Junior Notes B ($500.0 million) and Senior Notes L ($375.0 million). Of the $42.3 million gain, $10.6 million relates to the Junior Notes B and the remainder to the Senior Notes L and its successor debt.
 
(6)   EPO entered into these transactions related to its issuance of the Senior Notes L (including its successor debt) in August 2007 ($500.0 million) and anticipated issuance of debt during the first half of 2008 ($250.0 million).
 
(7)   Terminations relate to the issuance of the Senior Notes L and its successor debt.
 
(8)   EPO entered into these transactions in anticipated issuance of debt during the first half of 2008.
Commodity Risk Hedging Program
          The prices of natural gas, NGLs and certain petrochemical products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control. In order to manage the price risks associated with such products, we may enter into commodity financial instruments.
          The primary purpose of our commodity risk management activities is to hedge our exposure to price risks associated with (i) natural gas purchases, (ii) the value of NGL production and inventories, (iii) related firm commitments, (iv) fluctuations in transportation revenues where the underlying fees are based on natural gas index prices and (v) certain anticipated transactions involving either natural gas, NGLs or certain petrochemical products. From time to time, we inject natural gas into storage and utilize hedging instruments to lock in the value of our inventory positions. The commodity financial instruments we utilize may be settled in cash or with another financial instrument.
          The fair value of our commodity financial instrument portfolio, which primarily consisted of cash flow hedges, at December 31, 2007 was a liability of $19.3 million. During the years ended December 31, 2007, 2006 and 2005, we recorded a $28.6 million loss, $10.3 million income and $1.1 million income, respectively, related to our commodity financial instruments, which is included in operating costs and expenses on our Statements of Consolidated Operations. Included in the $28.6 million loss recorded during 2007, was ineffectiveness of $0.9 million (an expense) related to our commodity hedges. These contracts will terminate during 2008, and any amounts remaining in accumulated other comprehensive income will be recorded in earnings.

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Foreign Currency Hedging Program
          We are exposed to foreign currency exchange rate risk through our Canadian NGL marketing subsidiary and certain construction agreements with respect to our Pioneer processing plant where payments are indexed to the Canadian dollar. As a result, we could be adversely affected by fluctuations in the foreign currency exchange rate between the U.S. dollar and the Canadian dollar. We attempt to hedge this risk using foreign exchange purchase contracts to fix the exchange rate.
          Mark-to-market accounting is utilized for those foreign exchange contracts associated with our Canadian NGL marketing business. The duration of these contracts is typically one month. As of December 31, 2007, $4.7 million of these exchange contracts were outstanding, all of which settled in January 2008. In January 2008, we entered into $3.7 million of such instruments.
          The foreign exchange contracts associated with our construction activities are accounted for using hedge accounting. At December 31, 2007, the fair value of these contracts was $1.3 million. These contracts settle through May 2008.
Fair Value Information
          Cash and cash equivalents, accounts receivable, accounts payable and accrued expenses are carried at amounts which reasonably approximate their fair values due to their short-term nature. The estimated fair values of our fixed rate debt are based on quoted market prices for such debt or debt of similar terms and maturities. The carrying amounts of our variable rate debt obligations reasonably approximate their fair values due to their variable interest rates. The fair values associated with our interest rate and commodity hedging portfolios were developed using available market information and appropriate valuation techniques. The following table presents the estimated fair values of our financial instruments at the dates indicated:
                                 
    At December 31, 2007     At December 31, 2006  
       
    Carrying     Fair     Carrying     Fair  
Financial Instruments   Value     Value     Value     Value  
 
Financial assets:
                               
Cash and cash equivalents
  $ 92,866     $ 92,866     $ 46,286     $ 46,286  
Accounts receivable
    2,010,544       2,010,544       1,323,028       1,323,028  
Commodity financial instruments (1)
    338       338       1,472       1,472  
Foreign currency hedging financial instruments (2)
    1,308       1,308              
Interest rate hedging financial instruments (3)
    14,839       14,839       11,203       11,203  
Financial liabilities:
                               
Accounts payable and accrued expenses
    2,755,647       2,755,647       1,774,976       1,774,976  
Fixed-rate debt (principal amount)
    5,904,000       5,867,899       4,909,068       4,955,176  
Variable-rate debt
    992,500       992,500       420,000       420,000  
Commodity financial instruments (1)
    19,643       19,643       4,655       4,655  
Foreign currency hedging financial instruments (2)
    27       27              
Interest rate hedging financial instruments (3)
    23,422       23,422       29,060       29,060  
 
(1)   Represent commodity financial instrument transactions that either have not settled or have settled and not been invoiced. Settled and invoiced transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.
 
(2)   Relates to the hedging of our exposure to fluctuations in the Canadian dollar.
 
(3)   Represent interest rate hedging financial instrument transactions that have not settled. Settled transactions are reflected in either accounts receivable or accounts payable depending on the outcome of the transaction.
Note 8. Cumulative Effect of Changes in Accounting Principles
          During the years ended December 31, 2006 and 2005, we recorded various amounts related to the cumulative effect of changes in accounting principles, including a benefit of $1.5 million in January 2006 related to the implementation of SFAS 123(R) and a charge of $4.2 million in December 2005 related to our implementation of FIN 47.

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          See Note 6 regarding the balance sheet impact of adopting SFAS 158 at December 31, 2006, which had no effect on net income.
     Effect of Implementation of Staff Accounting Bulletin (“SAB”) 108
          SAB 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements,” addresses how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. This SAB requires us to quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. The provisions of SAB 108 did not have a material impact on our consolidated financial statements.
     Effect of Implementation of SFAS 123(R)
          SFAS 123(R) requires us to recognize compensation expense related to unit-based awards based on the fair value of the award at grant date. The fair value of restricted unit awards is based on the market price of the underlying common units on the date of grant. The fair value of other unit-based awards is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an equity-classified award is amortized to earnings on a straight-line basis over the requisite service or vesting period for equity-classified awards. Compensation for liability-classified awards is recognized over the requisite service or vesting period of an award based on the fair value of the award remeasured at each reporting period. Liability awards will be cash settled upon vesting.
          Upon adoption of SFAS 123(R), we recognized, as a benefit, the cumulative effect of a change in accounting principle of $1.5 million based on the SFAS 123(R) requirement to recognize compensation expense based upon the grant date fair value of unit-based awards and the application of an estimated forfeiture rate to unvested awards. See Notes 2 and 5 for additional information regarding our accounting for equity awards.
     Effect of Implementation of FIN 47
          In December 2005, we adopted FIN 47, “Accounting for Conditional Asset Retirement Obligations – An Interpretation for FAS 143,” which required us to record a liability for AROs in which the timing and/or amount of settlement of the obligation is uncertain. These conditional asset retirement obligations were not addressed in SFAS 143, which we adopted on January 1, 2003. We recorded a charge of $4.2 million in connection with our implementation of FIN 47, which represents the depreciation and accretion expense we would have recognized in prior periods had we recorded these conditional asset retirement obligations when incurred. See Note 10 for additional information regarding our AROs.

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          The following table shows unaudited pro forma net income for the years ended December 31, 2006 and 2005, assuming these accounting changes noted above were applied retroactively to January 1, 2005.
                 
    For the Years Ended
    December 31,
    2006   2005
     
Pro Forma income statement amounts:
               
Historical net income
  $ 601,155     $ 419,508  
Adjustments to derive pro forma net income:
               
Effect of implementation of SFAS 123(R):
               
Remove cumulative effect of change in accounting principle recorded in January 2006
    (1,472 )      
Additional compensation expense that would have been recorded for unit options
          (708 )
Remove compensation expense related to awards of profits interests in EPE Unit L.P.
          1,271  
Effect of implementation of FIN 47:
               
Remove cumulative effect of change in accounting principle recorded in December 2005
          4,208  
Record depreciation and accretion expense associated with conditional asset retirement obligations
          (735 )
     
Pro forma net income
    599,683       423,544  
EPGP interest
    (96,969 )     (71,077 )
     
Pro forma net income available to limited partners
  $ 502,714     $ 352,467  
     
 
               
Pro forma per unit data (basic):
               
Historical units outstanding
    414,442       382,463  
Per unit data:
               
As reported
  $ 1.22     $ 0.91  
     
Pro forma
  $ 1.21     $ 0.92  
     
Pro forma per unit data (diluted):
               
Historical units outstanding
    414,759       382,963  
Per unit data:
               
As reported
  $ 1.22     $ 0.91  
     
Pro forma
  $ 1.21     $ 0.92  
     
Note 9. Inventories
          Our inventory amounts were as follows at the dates indicated:
                 
    At December 31,  
    2007     2006  
     
Working inventory (1)
  $ 342,589     $ 387,973  
Forward-sales inventory (2)
    11,693       35,871  
     
Total inventory
  $ 354,282     $ 423,844  
     
 
(1)   Working inventory is comprised of inventories of natural gas, NGLs and certain petrochemical products that are either available-for-sale or used in the provision for services.
 
(2)   Forward sales inventory consists of segregated NGL and natural gas volumes dedicated to the fulfillment of forward-sales contracts.
          Our inventory values reflect payments for product purchases, freight charges associated with such purchase volumes, terminal and storage fees, vessel inspection costs, demurrage charges and other related costs. We value our inventories at the lower of average cost or market.
          Operating costs and expenses, as presented on our Statements of Consolidated Operations, include cost of sales amounts related to the sale of inventories. Our costs of sales were $14.5 billion, $11.8 billion and $10.3 billion for the years ended December 31, 2007, 2006 and 2005, respectively.

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          In those instances where we take ownership of inventory volumes through percent-of-liquids contracts and similar arrangements (as opposed to actually purchasing volumes for cash from third parties, see Note 4), these volumes are valued at market-related prices during the month in which they are acquired. We capitalize as a component of inventory those ancillary costs (e.g. freight-in and other handling and processing charges) incurred in connection with volumes obtained through such contracts.
          Due to fluctuating commodity prices in the NGL, natural gas and petrochemical industry, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of our inventories exceed their net realizable value. These non-cash charges are a component of cost of sales in the period they are recognized and generally affect our segment operating results in the following manner:
  §   Write-downs of NGL inventories are recorded as a cost of our NGL marketing activities within our NGL Pipelines & Services business segment;
 
  §   Write-downs of natural gas inventories are recorded as a cost of our natural gas pipeline operations within our Onshore Natural Gas Pipelines & Services business segment; and
 
  §   Write-downs of petrochemical inventories are recorded as a cost of our petrochemical marketing activities or octane additive production business within our Petrochemical Services business segment, as applicable.
          For the years ended December 31, 2007, 2006 and 2005, we recognized LCM adjustments of approximately $13.3 million, $18.6 million and $21.9 million, respectively. To the extent our commodity hedging strategies address inventory-related risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 7 for a description of our commodity hedging activities.
Note 10. Property, Plant and Equipment
          Our property, plant and equipment values and accumulated depreciation balances were as follows at the dates indicated:
                         
    Estimated    
    Useful Life   At December 31,
    in Years   2007   2006
     
Plants and pipelines (1)
    3-35  (5)   $ 10,884,819     $ 8,774,683  
Underground and other storage facilities (2)
    5-35  (6)     720,795       596,649  
Platforms and facilities (3)
    23-31       637,812       161,839  
Transportation equipment (4)
    3-10       32,627       27,008  
Land
            48,172       40,010  
Construction in progress
            1,173,988       1,734,083  
             
Total
            13,498,213       11,334,272  
Less accumulated depreciation
            1,910,949       1,501,725  
             
Property, plant and equipment, net
          $ 11,587,264     $ 9,832,547  
             
 
(1)     Plants and pipelines include processing plants; NGL, petrochemical, oil and natural gas pipelines; terminal loading and unloading facilities; office furniture and equipment; buildings; laboratory and shop equipment; and related assets.
 
(2)   Underground and other storage facilities include underground product storage caverns; storage tanks; water wells; and related assets.
 
(3)   Platforms and facilities include offshore platforms and related facilities and other associated assets.
 
(4)   Transportation equipment includes vehicles and similar assets used in our operations.
 
(5)   In general, the estimated useful lives of major components of this category are as follows: processing plants, 20-35 years; pipelines, 18-35 years (with some equipment at 5 years); terminal facilities, 10-35 years; office furniture and equipment, 3-20 years; buildings 20-35 years; and laboratory and shop equipment, 5-35 years.
 
(6)   In general, the estimated useful lives of major components of this category are as follows: underground storage facilities, 20-35 years (with some components at 5 years); storage tanks, 10-35 years; and water wells, 25-35 years (with some components at 5 years).

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          The following table summarizes our depreciation expense and capitalized interest amounts for the periods indicated:
                         
    For the Years Ended December 31,
    2007   2006   2005
Depreciation expense (1)
  $ 414,901     $ 350,832     $ 328,736  
Capitalized interest (2)
  $ 75,476     $ 55,660     $ 22,046  
 
(1)   Depreciation expense is a component of operating costs and expenses as presented in our Statements of Consolidated Operations.
 
(2)   Capitalized interest increases the carrying value of the associated asset and reduces interest expense during the period it is recorded.
     Asset retirement obligations
          We have recorded asset retirement obligations related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. In general, our asset retirement obligations primarily result from (i) right-of-way agreements associated with our pipeline operations, (ii) leases of plant sites and (iii) regulatory requirements triggered by the abandonment or retirement of certain underground storage assets and offshore facilities. In addition, our asset retirement obligations may result from the renovation or demolition of certain assets containing hazardous substances such as asbestos.
          Previously, we recorded asset retirement obligations associated with the future retirement and removal activities of certain offshore assets located in the Gulf of Mexico. In December 2005, we adopted FIN 47 and recorded an additional $10.1 million in connection with conditional asset retirement obligations. The cumulative effect of this change in accounting principle for years prior to 2005 was a non-cash charge of $4.2 million. None of our assets are legally restricted for purposes of settling asset retirement obligations.
          The following table presents information regarding our asset retirement obligations since December 31, 2005.
         
Asset retirement obligation liability balance, December 31, 2005
  $ 16,795  
Liabilities incurred
    1,977  
Liabilities settled
    (1,348 )
Revisions in estimated cash flows
    5,650  
Accretion expense
    1,329  
 
     
Asset retirement obligation liability balance, December 31, 2006
    24,403  
Liabilities incurred
    1,673  
Liabilities settled
    (5,069 )
Revisions in estimated cash flows
    15,645  
Accretion expense
    3,962  
 
     
Asset retirement obligation liability balance, December 31, 2007
  $ 40,614  
 
     
          Property, plant and equipment at December 31, 2007 and 2006 includes $10.6 million and $3.0 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. Also, based on information currently available, we estimate that accretion expense will approximate $2.0 million for each of the years 2008 and 2009, $2.1 million for 2010, $2.3 million for 2011 and $2.5 million for 2012.
          Certain of our unconsolidated affiliates have AROs recorded at December 31, 2007 and 2006 relating to contractual agreements and regulatory requirements. These amounts are immaterial to our financial statements.

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Note 11. Investments In and Advances to Unconsolidated Affiliates
          We own interests in a number of related businesses that are accounted for using the equity method of accounting. Our investments in and advances to unconsolidated affiliates are grouped according to the business segment to which they relate. See Note 16 for a general discussion of our business segments. The following table shows our investments in and advances to unconsolidated affiliates at the dates indicated.
                         
    Ownership   Investments in and advances to
    Percentage at   Unconsolidated Affiliates at
    December 31,   December 31,   December 31,
    2007   2007   2006
     
NGL Pipelines & Services:
                       
VESCO
    13.1 %   $ 40,129     $ 39,618  
K/D/S Promix, L.L.C. (“Promix”)
    50 %     51,537       46,140  
Baton Rouge Fractionators LLC (“BRF”)
    32.3 %     25,423       25,471  
Onshore Natural Gas Pipelines & Services:
                       
Jonah Gas Gathering Company (“Jonah”)
    19.4 %     235,837       120,370  
Evangeline (1)
    49.5 %     3,490       4,221  
Offshore Pipelines & Services:
                       
Poseidon Oil Pipeline, L.L.C. (“Poseidon”)
    36 %     58,423       62,324  
Cameron Highway Oil Pipeline Company (“Cameron Highway”) (2)
    50 %     256,588       60,216  
Deepwater Gateway, L.L.C. (“Deepwater Gateway”)
    50 %     111,221       117,646  
Neptune Pipeline Company, L.L.C. (“Neptune”) (3)
    25.7 %     55,468       58,789  
Nemo Gathering Company, LLC (“Nemo”) (4)
    33.9 %     2,888       11,161  
Petrochemical Services:
                       
Baton Rouge Propylene Concentrator, LLC (“BRPC”)
    30 %     13,282       13,912  
La Porte (5)
    50 %     4,053       4,691  
             
Total
          $ 858,339     $ 564,559  
             
 
(1)   Refers to our ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively.
 
(2)   During the year ended December 31, 2007, we contributed $216.5 million to Cameron Highway to fund our portion of the repayment of Cameron Highway’s debt.
 
(3)   The December 31, 2006 amount includes a $7.4 million non-cash impairment charge attributable to our investment in Neptune.
 
(4)   The December 31, 2007 amount includes a $7.0 million non-cash impairment charge attributable to our investment in Nemo.
 
(5)   Refers to our ownership interests in La Porte Pipeline Company, L.P. and La Porte GP, LLC, collectively.
          On occasion, the price we pay to acquire an ownership interest in a company exceeds the underlying book value of the capital accounts we acquire. Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates. At December 31, 2007 and 2006, our investments in Promix, La Porte, Neptune, Poseidon, Cameron Highway, Nemo and Jonah included excess cost amounts totaling $43.8 million and $38.7 million, respectively, all of which were attributable to the fair value of the underlying tangible assets of these entities exceeding their book carrying values at the time of our acquisition of interests in these entities. To the extent that we attribute all or a portion of an excess cost amount to higher fair values, we amortize such excess cost as a reduction in equity earnings in a manner similar to depreciation. To the extent we attribute an excess cost amount to goodwill, we do not amortize this amount but it is subject to evaluation for impairment. Amortization of such excess cost amounts was $2.6 million, $2.1 million and $2.3 million for the years ended December 31, 2007, 2006 and 2005, respectively.

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          The following table presents our equity in income (loss) of unconsolidated affiliates for the periods indicated:
                         
    For the Year Ended December 31,
    2007   2006   2005
     
NGL Pipelines & Services:
                       
Dixie
  $     $     $ 1,103  
VESCO
    3,507       1,719       1,412  
Belle Rose
                (151 )
Promix
    514       1,353       1,876  
BRF
    2,010       2,643       1,313  
Onshore Natural Gas Pipelines & Services:
                       
Evangeline
    183       958       331  
Coyote
          1,676       2,053  
Jonah
    9,357       238        
Offshore Pipelines & Services:
                       
Poseidon
    10,020       11,310       7,279  
Cameron Highway (1)
    (11,200 )     (11,000 )     (15,872 )
Deepwater Gateway
    20,606       18,392       10,612  
Neptune (2)
    (821 )     (8,294 )     2,019  
Nemo (3)
    (5,977 )     1,501       1,774  
Starfish Pipeline Company, LLC (“Starfish”) (4)
                313  
Petrochemical Services:
                       
BRPC
    2,266       1,864       1,224  
La Porte
    (807 )     (795 )     (738 )
     
Total
  $ 29,658     $ 21,565     $ 14,548  
       
 
(1)   Equity earnings from Cameron Highway for the year ended December 31, 2005 were reduced by a charge of $11.5 million for costs associated with the refinancing of Cameron Highway’s project debt.
 
(2)   Equity earnings from Neptune for 2006 include a $7.4 million non-cash impairment charge.
 
(3)   Equity earnings from Nemo for 2007 include a $7.0 million non-cash impairment charge.
 
(4)   We were required under a consent decree published for comment by the U.S. Federal Trade Commission on September 30, 2004 to sell our 50% interest in Starfish. On March 31, 2005, we sold this asset to a third-party.
     NGL Pipelines & Services
          At December 31, 2007, our NGL Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:
          VESCO. We own a 13.1% interest in VESCO, which owns a natural gas processing facility and related assets located in south Louisiana.
          Promix. We own a 50.0% interest in Promix, which owns an NGL fractionation facility and related storage and pipeline assets located in south Louisiana.
          BRF. We own an approximate 32.3% interest in BRF, which owns an NGL fractionation facility located in south Louisiana.

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          The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s current unconsolidated affiliates are summarized below.
                 
    At December 31,
    2007   2006
     
BALANCE SHEET DATA:
               
Current assets
  $ 112,352     $ 62,138  
Property, plant and equipment, net
    270,586       242,083  
Other assets
    11,686       12,189  
     
Total assets
  $ 394,624     $ 316,410  
     
 
               
Current liabilities
  $ 75,314     $ 30,686  
Other liabilities
    9,095       8,117  
Combined equity
    310,215       277,607  
     
Total liabilities and combined equity
  $ 394,624     $ 316,410  
     
                         
    For the Year Ended December 31,
    2007   2006   2005
     
INCOME STATEMENT DATA:
                       
Revenues
  $ 220,381     $ 190,320     $ 207,775  
Operating income (loss)
    41,147       (26,885 )     6,696  
Net income (loss)
    26,506       (25,543 )     6,509  
     Onshore Natural Gas Pipelines & Services
          At December 31, 2007, our Onshore Natural Gas Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:
          Evangeline. We own an approximate 49.5% aggregate interest in Evangeline, which owns a natural gas pipeline located in south Louisiana. A subsidiary of Acadian Gas, LLC owns the Evangeline interests, which were contributed to Duncan Energy Partners in February 2007 in connection with its initial public offering (see Note 17).
          Coyote. We owned a 50.0% interest in Coyote during 2005, which owns a natural gas treating facility located in the San Juan Basin of southwestern Colorado. During 2006, we sold our interest in Coyote and recorded a gain on the sale of $3.3 million.
          Jonah. Our equity interest in Jonah at December 31, 2007 is based on capital contributions we made to Jonah in connection with its Phase V expansion project through this date. We completed Phase I of this expansion in July 2007 entitling us to approximately 19.4% in earnings and ownership with the remaining 80.6% entitlement to TEPPCO. See Note 17 for additional information regarding our Jonah affiliate. Jonah owns the Jonah Gas Gathering System located in the Greater Green River Basin of southwestern Wyoming.

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          The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s current unconsolidated affiliates are summarized below.
                 
    At December 31,
    2007   2006
     
BALANCE SHEET DATA:
               
Current assets
  $ 83,962     $ 65,048  
Property, plant and equipment, net
    915,572       639,641  
Other assets
    176,091       192,027  
     
Total assets
  $ 1,175,625     $ 896,716  
     
 
               
Current liabilities
  $ 43,951     $ 49,708  
Other liabilities
    25,002       28,802  
Combined equity
    1,106,672       818,206  
     
Total liabilities and combined equity
  $ 1,175,625     $ 896,716  
     
                         
    For the Year Ended December 31,
    2007   2006   2005
     
INCOME STATEMENT DATA:
                       
Revenues
  $ 477,077     $ 372,240     $ 347,561  
Operating income
    98,549       48,387       9,142  
Net income
    93,491       40,608       4,668  
     Offshore Pipelines & Services
          At December 31, 2007, our Offshore Pipelines & Services segment included the following unconsolidated affiliates accounted for using the equity method:
          Poseidon. We own a 36.0% interest in Poseidon, which owns a crude oil pipeline that gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico for delivery to onshore locations in south Louisiana.
          Cameron Highway. We own a 50.0% interest in Cameron Highway, which owns a crude oil pipeline that gathers production from deepwater areas of the Gulf of Mexico, primarily the South Green Canyon area, for delivery to refineries and terminals in southeast Texas. The Cameron Highway Oil Pipeline commenced operations during the first quarter of 2005.
          Cameron Highway repaid its $365.0 million Series A notes and $50.0 million Series B notes in 2007 using cash contributions from its partners. We funded our 50% share of the capital contributions using borrowings under EPO’s Multi-Year Revolving Credit Facility. Cameron Highway incurred a $14.1 million make-whole premium in connection with the repayment of its Series A notes.
          Deepwater Gateway. We own a 50.0% interest in Deepwater Gateway, which owns the Marco Polo platform located in the Gulf of Mexico. The Marco Polo platform processes crude oil and natural gas production from the Marco Polo, K2, K2 North and Ghengis Khan fields located in the South Green Canyon area of the Gulf of Mexico.
          Neptune. We own a 25.7% interest in Neptune, which owns the Manta Ray Offshore Gathering and Nautilus Systems, which are natural gas pipelines located in the Gulf of Mexico.
          Nemo. We own a 33.9% interest in Nemo, which owns the Nemo Gathering System, which is a natural gas pipeline located in the Gulf of Mexico.
          In connection with obtaining regulatory approval for the GulfTerra Merger, we were required by the U.S. Federal Trade Commission to sell our ownership interest in Starfish by March 31, 2005. In March 2005, we sold this asset to a third-party for $42.1 million in cash and realized a gain on the sale of $5.5 million.

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          The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s current unconsolidated affiliates are summarized below.
                 
    At December 31,
    2007   2006
     
BALANCE SHEET DATA:
               
Current assets
  $ 46,795     $ 56,689  
Property, plant and equipment, net
    1,122,108       1,178,811  
Other assets
    4,338       10,108  
     
Total assets
  $ 1,173,241     $ 1,245,608  
     
 
               
Current liabilities
  $ 19,720     $ 22,043  
Other liabilities
    96,791       510,773  
Combined equity
    1,056,730       712,792  
     
Total liabilities and combined equity
  $ 1,173,241     $ 1,245,608  
     
                         
    For the Year Ended December 31,
    2007   2006   2005
|     | |
INCOME STATEMENT DATA:
                       
Revenues
  $ 156,780     $ 153,996     $ 154,297  
Operating income
    85,550       71,977       78,027  
Net income
    53,590       42,732       29,086  
          Neptune owns the Manta Ray Offshore Gathering System (“Manta Ray”) and Nautilus Pipeline System (“Nautilus”). Manta Ray gathers natural gas originating 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 the Nautilus pipeline. Nautilus connects our Manta Ray pipeline to our Neptune natural gas processing plant located in south Louisiana. Due to a recent decrease in throughput volumes on the Manta Ray and Nautilus pipelines, we evaluated our 25.7% investment in Neptune for impairment during the third quarter of 2006. The decrease in throughput volumes is primarily due to underperformance of certain fields, natural depletion and hurricane-related delays in starting new production. These factors contributed to significant delays in throughput volumes Neptune expects to receive. As a result, Neptune has experienced operating losses in recent periods.
          At December 31, 2005, the carrying value of our investment in Neptune was $68.1 million, which included $10.9 million of excess cost related to its original acquisition in 2001. Our review of Neptune’s estimated cash flows during the third quarter of 2006 indicated that the carrying value of our investment exceeded its fair value, which resulted in a non-cash impairment charge of $7.4 million. This loss is recorded as a component of “Equity in income of unconsolidated affiliates” in our Statement of Consolidated Operations for the year ended December 31, 2006. After recording this impairment charge, the carrying value of our investment in Neptune at December 31, 2006 was $58.8 million.
          Nemo was formed in 1999 to construct, own and operate the Nemo Gathering System, a 24-mile natural gas gathering system in the Gulf of Mexico offshore Louisiana. The Nemo Gathering System, which began operations in 2001, gathers natural gas from certain developments in the Green Canyon area of the Gulf of Mexico to a pipeline interconnect with the Manta Ray Gathering System. Due to a recent decrease in throughput volumes on the Nemo Gathering System, we evaluated our 33.9% investment in Nemo for impairment during the second quarter of 2007. The decrease in throughput volumes is primarily due to underperformance of certain fields and natural depletion.
          At December 31, 2006, the carrying value of our investment in Nemo was $11.2 million, which included $0.6 million of excess cost related to its original acquisition in 2001. Our review of Nemo’s estimated future cash flows during the second quarter of 2007 indicated that the carrying value of our investment exceeded its fair value, which resulted in a non-cash impairment charge of $7.0 million. This loss is recorded as a component of “Equity in income of unconsolidated affiliates” in our Statement of Consolidated Operations for the year ended December 31, 2007. After recording this impairment charge, the carrying value of our investment in Nemo at December 31, 2007 was $2.9 million.

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          Our investments in Neptune and Nemo were written down to fair value, which management estimated using recognized business valuation techniques. The fair value analysis is based upon management’s expectation of future cash flows, which incorporates certain industry information and assumptions made by management. For example, the individual reviews of Neptune and Nemo included management estimates regarding natural gas reserves of producers served by both Neptune and Nemo, respectively. If the assumptions underlying our fair value analysis change and expected cash flows are reduced, additional impairment charges may result.
     Petrochemical Services
          At December 31, 2007, our Petrochemical Services segment included the following unconsolidated affiliates accounted for using the equity method:
          BRPC. We own a 30.0% interest in BRPC, which owns a propylene fractionation facility located in south Louisiana.
          La Porte. We own an aggregate 50.0% interest in La Porte, which owns a propylene pipeline extending from Mont Belvieu, Texas to La Porte, Texas.
          The combined balance sheet information for the last two years and results of operations data for the last three years of this segment’s current unconsolidated affiliates are summarized below.
                 
    At December 31,
    2007   2006
     
BALANCE SHEET DATA:
               
Current assets
  $ 3,187     $ 3,324  
Property, plant and equipment, net
    47,322       51,159  
     
Total assets
  $ 50,509     $ 54,483  
     
 
               
Current liabilities
  $ 970     $ 832  
Other liabilities
    2       2  
Combined equity
    49,537       53,649  
     
Total liabilities and combined equity
  $ 50,509     $ 54,483  
     
                         
    For the Year Ended December 31,
    2007   2006   2005
|     | |
INCOME STATEMENT DATA:
                       
Revenues
  $ 19,844     $ 19,014     $ 16,849  
Operating income
    5,961       4,626       2,606  
Net income
    6,029       4,729       2,650  
Note 12. Business Combinations
     2007 Transactions
          Our expenditures for business combination during the year ended December 31, 2007 were $35.8 million, which primarily reflect the $35.0 million we spent to acquire the South Monco natural gas pipeline business (“South Monco”) in December 2007. This business includes approximately 128 miles of natural gas pipelines located in southeast Texas. The remaining business combination-related amounts for 2007 consist of purchase price adjustments to prior period transactions.
          On a pro forma consolidated basis, our revenues, costs and expenses, operating income, net income and earnings per unit amounts would not have differed materially from those we actually reported for 2007 and 2006 due to immaterial nature of our 2007 business combination transactions.

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          We accounted for our 2007 business combinations using the purchase method of accounting and, accordingly, such costs have been allocated to assets acquired and liabilities assumed based on estimated preliminary fair values. Such preliminary values have been developed using recognized business valuation techniques and are subject to change pending a final valuation analysis. We expect to finalize the purchase price allocations for these transactions during 2008.
                         
    South Monco        
    Acquisition   Other   Total
     
Assets acquired in business combination:
                       
Property, plant and equipment, net
  $ 36,000     $ 8,386     $ 44,386  
Intangible assets
          (8,460 )     (8,460 )
     
Total assets acquired
    36,000       (74 )     35,926  
     
Liabilities assumed in business combination:
                       
Other long-term liabilities
    (1,000 )     (244 )     (1,244 )
     
Total liabilities assumed
    (1,000 )     (244 )     (1,244 )
     
Total assets acquired less liabilities assumed
    35,000       (318 )     34,682  
Total cash used for business combinations
    35,000       793       35,793  
     
Goodwill
  $     $ 1,111     $ 1,111  
     
     2006 Transactions
          Our expenditures for business combinations during the year ended December 31, 2006 were $276.5 million and primarily reflect the Encinal and Piceance Creek acquisitions described below.
          Encinal Acquisition. In July  2006, we acquired the Encinal and Canales natural gas gathering systems and related gathering and processing contracts that comprised the South Texas natural gas transportation and processing business of an affiliate of Lewis Energy Group, L.P. (“Lewis”). The aggregate value of total consideration we paid or issued to complete this business combination (referred to as the “Encinal acquisition”) was $326.3 million, which consisted of $145.2 million in cash and 7,115,844 of our common units.
          The Encinal and Canales gathering systems are located in South Texas and are connected to over 1,450 natural gas wells producing from the Olmos and Wilcox formations. The Encinal system consists of 449 miles of pipeline, which is comprised of 277 miles of pipeline we acquired from Lewis in this transaction and 172 miles of pipeline that we own and had previously leased to Lewis. The Canales gathering system is comprised of 32 miles of pipeline. Currently, natural gas volumes gathered by the Encinal and Canales systems are transported by our existing Texas Intrastate System and are processed by our South Texas natural gas processing plants.
          The Encinal and Canales gathering systems will be supported by a life of reserves gathering and processing dedication by Lewis related to its natural gas production from the Olmos formation. In addition, we entered into a 10-year agreement with Lewis for the transportation of natural gas treated at its proposed Big Reef facility. This facility will treat natural gas from the southern portion of the Edwards Trend in South Texas. We also entered into a 10-year agreement with Lewis for the gathering and processing of rich gas it produces from below the Olmos formation.
          The total consideration we paid or granted to Lewis in connection with the Encinal acquisition is as follows:
         
Cash payment to Lewis
  $ 145,197  
Fair value of our 7,115,844 common units issued to Lewis
    181,112  
 
     
Total consideration
  $ 326,309  
 
     
          In accordance with purchase accounting, the value of our common units issued to Lewis was based on the average closing price of such units immediately prior to and after the transaction was announced on July 12, 2006. For purposes of this calculation, the average closing price was $25.45 per unit.

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          Since the closing date of the Encinal acquisition was July 1, 2006, our Statements of Consolidated Operations do not include any earnings from these assets prior to this date. Given the relative size of the Encinal acquisition to our other business combination transactions during 2006, the following table presents selected pro forma earnings information for the years ended December 31, 2006 and 2005 as if the Encinal acquisition had been completed on January 1, 2006 and 2005, respectively, instead of July 1, 2006. This information was prepared based on financial data available to us and reflects certain estimates and assumptions made by our management. Our pro forma financial information is not necessarily indicative of what our consolidated financial results would have been had the Encinal acquisition actually occurred on January 1, 2005. The amounts shown in the following table are in millions, except per unit amounts.
                 
    For the Year Ended December 31,
    2006   2005
     
Pro forma earnings data:
               
Revenues
  $ 14,066     $ 12,408  
     
Costs and expenses
  $ 13,228     $ 11,758  
     
Operating income
  $ 859     $ 664  
     
Net income
  $ 598     $ 418  
     
Basic earnings per unit (“EPU”):
               
Units outstanding, as reported
    414       382  
     
Units outstanding, pro forma
    422       389  
     
Basic EPU, as reported
  $ 1.22     $ 0.91  
     
Basic EPU, pro forma
  $ 1.19     $ 0.89  
     
Diluted EPU:
               
Units outstanding, as reported
    415       383  
     
Units outstanding, pro forma
    422       390  
     
Diluted EPU, as reported
  $ 1.22     $ 0.91  
     
Diluted EPU, pro forma
  $ 1.19     $ 0.89  
     
          Piceance Creek Acquisition. In December  2006, one of our affiliates, Enterprise Gas Processing, LLC, purchased a 100% interest in Piceance Creek Pipeline, LLC (“Piceance Creek”), for cash consideration of $100.0 million. Piceance Creek was wholly owned by EnCana Oil & Gas (“EnCana”).
          The assets of Piceance Creek consist of a recently constructed 48-mile natural gas gathering pipeline, the Piceance Creek Gathering System, located in the Piceance Basin of northwestern Colorado. The Piceance Creek Gathering System has a transportation capacity of 1.6 billion cubic feet per day (“Bcf/d”) of natural gas and 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. Connectivity to EnCana’s Great Divide Gathering System will provide the Piceance Creek Gathering System with access to production from the southern portion of the Piceance basin, including production from EnCana’s Mamm Creek field. The Piceance Creek Gathering System was placed in service in January 2007 and began transporting initial volumes of approximately 300 million cubic feet per day (“MMcf/d”) of natural gas. Currently, we transport approximately 520 MMcf/d of natural gas volumes, with a significant portion of these volumes being produced by EnCana, one of the largest natural gas producers in the region. In conjunction with our acquisition of Piceance Creek, EnCana signed a long-term, fixed fee gathering agreement with us and dedicated significant production to the Piceance Creek Gathering System for the life of the associated lease holdings.
          Other Transactions. In addition to the Encinal and Piceance Creek acquisitions, our business combinations during 2006 included the purchase of (i) an additional 8.2% ownership interest in Dixie for $12.9 million, (ii) all of the capital stock of an affiliated NGL marketing company located in Canada from related parties for $17.7 million (see Note 17) and (iii) a storage business in Flagstaff, Arizona for $0.7 million.

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     2005 Transactions
          Our expenditures for business combinations during the year ended December 31, 2005 were $326.6 million. In January 2005, we acquired indirect ownership interests in the Indian Springs Gathering System and Indian Springs natural gas processing plant for $74.9 million. In January and February 2005, we acquired an additional 46% of the ownership interests in Dixie for $68.6 million. In June 2005, we acquired additional indirect ownership interests in our Mid-America Pipeline System and Seminole Pipeline for $25.0 million. Also in June 2005, we acquired an additional 41.7% ownership interest in Belle Rose, which owns a NGL pipeline located in Louisiana, for $4.4 million. In July 2005, we purchased three underground NGL storage facilities and four propane terminals from Ferrellgas L.P. (“Ferrellgas”) for $145.5 million in cash. Dixie and Belle Rose became consolidated subsidiaries of ours in 2005 as a result of our acquisition of additional ownership interests in these two entities.
Note 13. Intangible Assets and Goodwill
     Identifiable Intangible Assets
          The following table summarizes our intangible assets at the dates indicated:
                                                 
    At December 31, 2007   At December 31, 2006
    Gross   Accum.   Carrying   Gross   Accum.   Carrying
    Value   Amort.   Value   Value   Amort.   Value
     
NGL Pipelines & Services:
                                               
Shell Processing Agreement
  $ 206,216     $ (78,252 )   $ 127,964     $ 206,216     $ (67,204 )   $ 139,012  
Encinal gas processing customer relationship
    127,119       (17,470 )     109,649       127,119       (6,049 )     121,070  
STMA and GulfTerra NGL Business customer relationships
    49,784       (17,537 )     32,247       49,784       (12,980 )     36,804  
Pioneer gas processing contracts
    37,752       (736 )     37,016       37,752             37,752  
Markham NGL storage contracts
    32,664       (14,154 )     18,510       32,664       (9,800 )     22,864  
Toca-Western contracts
    31,229       (8,718 )     22,511       31,229       (7,156 )     24,073  
Piceance Creek customer relationship
                      8,460             8,460  
Other
    35,261       (10,087 )     25,174       35,370       (7,455 )     27,915  
     
Segment total
    520,025       (146,954 )     373,071       528,594       (110,644 )     417,950  
     
Onshore Natural Gas Pipelines & Services:
                                               
San Juan Gathering System customer relationships
    331,311       (73,087 )     258,224       331,311       (52,318 )     278,993  
Petal & Hattiesburg natural gas storage contracts
    100,499       (27,931 )     72,568       100,499       (19,337 )     81,162  
Other
    31,741       (8,381 )     23,360       31,741       (5,747 )     25,994  
     
Segment total
    463,551       (109,399 )     354,152       463,551       (77,402 )     386,149  
     
Offshore Pipelines & Services:
                                               
Offshore pipeline & platform customer relationships
    205,845       (73,905 )     131,940       205,845       (54,636 )     151,209  
Other
    1,167       (49 )     1,118       1,167             1,167  
     
Segment total
    207,012       (73,954 )     133,058       207,012       (54,636 )     152,376  
     
Petrochemical Services:
                                               
Mont Belvieu propylene fractionation contracts
    53,000       (8,960 )     44,040       53,000       (7,445 )     45,555  
Other
    14,906       (2,227 )     12,679       3,674       (1,749 )     1,925  
     
Segment total
    67,906       (11,187 )     56,719       56,674       (9,194 )     47,480  
     
Total all segments
  $ 1,258,494     $ (341,494 )   $ 917,000     $ 1,255,831     $ (251,876 )   $ 1,003,955  
     
          We paid $11.2 million for certain air emission credits related to our Mont Belvieu complex in 2007. These items were recorded as intangible assets within our Petrochemical Services business segment.

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          The following table presents the amortization expense of our intangible assets by segment for the periods indicated:
                         
    For the Year Ended December 31,
    2007   2006   2005
     
NGL Pipelines & Services
  $ 36,419     $ 31,159     $ 26,350  
Onshore Natural Gas Pipelines & Services
    31,997       33,447       35,080  
Offshore Pipelines & Services
    19,318       22,156       25,515  
Petrochemical Services
    1,993       1,993       1,993  
     
Total all segments
  $ 89,727     $ 88,755     $ 88,938  
     
          Based on information currently available, we estimate that amortization expense associated with existing intangible assets will approximate $86.3 million in 2008, $80.4 million in 2009, $75.8 million in 2010, $70.1 million in 2011 and $60.7 million in 2012.
          In general, our intangible assets fall within two categories – contract-based intangible assets and customer relationships. Contract-based intangible assets represent commercial rights we acquired in connection with business combinations or asset purchases. Customer relationship intangible assets represent customer bases that we acquired in connection with business combinations and asset purchases. The values assigned to intangible assets are amortized to earnings using either (i) a straight-line approach or (ii) other methods that closely resemble the pattern in which the economic benefits of associated resource bases are estimated to be consumed or otherwise used, as appropriate.
          We acquired $141.3 million of intangible assets during the year ended December 31, 2006, primarily attributable to customer relationships we acquired in connection with the Encinal acquisition. The $132.9 million of intangible assets we acquired in connection with the Encinal acquisition (see Note 12) represents the value we assigned to customer relationships, particularly the long-term relationship we now have with Lewis through natural gas processing and gathering arrangements. We recorded $127.1 million in our NGL Pipelines & Services segment associated with processing arrangements and $5.8 million in our Onshore Natural Gas Pipelines & Services segment associated with gathering arrangements. These intangible assets will be amortized to earnings over a 20-year life using methods that closely resemble the pattern in which we estimate the depletion of the underlying natural gas resources to occur.
          We acquired numerous customer relationship and contract-based intangible assets in connection with the GulfTerra Merger. The customer relationship intangible assets represent the exploration and production, natural gas processing and NGL fractionation customer bases served by GulfTerra and the South Texas midstream assets at the time the merger was completed. The contract-based intangible assets represent the rights we acquired in connection with discrete contracts to provide storage services for natural gas and NGLs that GulfTerra had entered into prior to the merger.
          The value we assigned to these customer relationships is being amortized to earnings using methods that closely resemble the pattern in which the economic benefits of the underlying oil and natural gas resource bases from which the customers produce are estimated to be consumed or otherwise used. Our estimate of the useful life of each resource base is based on a number of factors, including reserve estimates, the economic viability of production and exploration activities and other industry factors. This group of intangible assets primarily consists of the (i) Offshore Pipelines & Platforms customer relationships; (ii) San Juan Gathering System customer relationships; (iii) Texas Intrastate pipeline customer relationships; and (iv) STMA and GulfTerra NGL Business customer relationships.
          The contract-based intangible assets we acquired in connection with the GulfTerra Merger are being amortized over the estimated useful life (or term) of each agreement, which we estimate to range from two to eighteen years. This group of intangible assets consists of the (i) Petal and Hattiesburg natural gas storage contracts and (ii) Markham NGL storage contracts.
          The Shell Processing Agreement grants us the right to process Shell’s (or its assignee’s) current and future production within the state and federal waters of the Gulf of Mexico. We acquired this

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intangible asset in connection with our 1999 purchase of certain of Shell’s midstream energy assets located along the Gulf Coast. The value of the Shell Processing Agreement is being amortized on a straight-line basis over the remainder of its initial 20-year contract term through 2019.
     Goodwill
          Goodwill represents the excess of the purchase price of an acquired business over the amounts assigned to assets acquired and liabilities assumed in the transaction. Goodwill is not amortized; however, it is subject to annual impairment testing. The following table summarizes our goodwill amounts by segment at the dates indicated:
                 
    At December 31,
    2007   2006
     
NGL Pipelines & Services
               
GulfTerra Merger
  $ 23,854     $ 23,854  
Acquisition of Indian Springs natural gas processing business
    13,162       13,162  
Encinal acquisition
    95,280       95,166  
Other
    21,410       20,413  
Onshore Natural Gas Pipelines & Services
               
GulfTerra Merger
    279,956       279,956  
Acquisition of Indian Springs natural gas gathering business
    2,165       2,165  
Offshore Pipelines & Services
               
GulfTerra Merger
    82,135       82,135  
Petrochemical Services
               
Acquisition of Mont Belvieu propylene fractionation business
    73,690       73,690  
     
Total
  $ 591,652     $ 590,541  
     
          Goodwill recorded in connection with the GulfTerra Merger can be attributed to our belief (at the time the merger was consummated) that the combined partnerships would benefit from the strategic location of each partnership’s assets and the industry relationships that each possessed. In addition, we expected that various operating synergies could develop (such as reduced general and administrative costs and interest savings) that would result in improved financial results for the merged entity. Based on miles of pipelines, GulfTerra was one of the largest natural gas gathering and transportation companies in the United States, serving producers in the central and western Gulf of Mexico and onshore in Texas and New Mexico. These regions offer us significant growth potential through the acquisition and construction of additional pipelines, platforms, processing and storage facilities and other midstream energy infrastructure.
          In 2006, the only significant change in goodwill was the recording of $95.2 million in connection with our preliminary purchase price allocation for the Encinal acquisition. Management attributes this goodwill to potential future benefits we may realize from our other south Texas processing and NGL businesses as a result of acquiring the Encinal business. Specifically, our acquisition of the long-term dedication rights associated with the Encinal business is expected to add value to our south Texas processing facilities and related NGL businesses due to increased volumes. The Encinal goodwill is recorded as part of the NGL Pipelines & Services business segment due to management’s belief that such future benefits will accrue to businesses classified within this segment.
          The remainder of our goodwill amounts is associated with prior acquisitions, principally that of our purchase of a propylene fractionation business in February 2002 and our acquisition of indirect ownership interests in the Indian Springs natural gas gathering and processing business in January 2005.

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Note 14. Debt Obligations
          Our consolidated debt obligations consisted of the following at the dates indicated:
                 
    At December 31,
    2007   2006
     
EPO senior debt obligations:
               
Multi-Year Revolving Credit Facility, variable rate, due November 2012 (1)
  $ 725,000     $ 410,000  
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010
    54,000       54,000  
Senior Notes B, 7.50% fixed-rate, due February 2011
    450,000       450,000  
Senior Notes C, 6.375% fixed-rate, due February 2013
    350,000       350,000  
Senior Notes D, 6.875% fixed-rate, due March 2033
    500,000       500,000  
Senior Notes E, 4.00% fixed-rate, due October 2007 (2)
          500,000  
Senior Notes F, 4.625% fixed-rate, due October 2009
    500,000       500,000  
Senior Notes G, 5.60% fixed-rate, due October 2014
    650,000       650,000  
Senior Notes H, 6.65% fixed-rate, due October 2034
    350,000       350,000  
Senior Notes I, 5.00% fixed-rate, due March 2015
    250,000       250,000  
Senior Notes J, 5.75% fixed-rate, due March 2035
    250,000       250,000  
Senior Notes K, 4.950% fixed-rate, due June 2010
    500,000       500,000  
Senior Notes L, 6.30% fixed-rate, due September 2017
    800,000        
Petal GO Zone Bonds, variable rate, due August 2034
    57,500        
Duncan Energy Partners’ debt obligation:
               
$300 Million Revolving Credit Facility, variable rate, due February 2011
    200,000        
Dixie Revolving Credit Facility, variable rate, due June 2010
    10,000       10,000  
Other, 8.75% fixed-rate, due June 2010 (3)
          5,068  
     
Total principal amount of senior debt obligations
    5,646,500       4,779,068  
EPO Junior Subordinated Notes A, due August 2066
    550,000       550,000  
EPO Junior Subordinated Notes B, due January 2068
    700,000        
     
Total principal amount of senior and junior debt obligations
    6,896,500       5,329,068  
Other, including unamortized discounts and premiums and changes in fair value (4)
    9,645       (33,478 )
     
Long-term debt
  $ 6,906,145     $ 5,295,590  
      
 
               
Standby letters of credit outstanding
  $ 1,100     $ 49,858  
     
 
(1)   In November 2007, EPO executed an amended and restated revolving credit agreement governing its Multi-Year Revolving Credit Facility. This new credit agreement increases the capacity from $1.25 billion to $1.75 billion and extends the maturity date of amounts borrowed under EPO’s Multi-Year Revolving Credit Facility from October 2011 to November 2012.
 
(2)   In accordance with SFAS 6, “Classification of Short-Term Obligations Expected to be Refinanced,” long-term and current maturities of debt reflects the classification of such obligations at December 31, 2006. With respect to Senior Notes E, EPO repaid this note in October 2007, using cash and available credit capacity under its then $1.25 billion Multi-Year Revolving Credit Facility.
 
(3)   Represents remaining debt obligations assumed in connection with the GulfTerra Merger, which were redeemed in the fourth quarter of 2007.
 
(4)   The December 31, 2007 amount includes an asset of $14.8 million related to fair value hedges offset by a net $5.2 million in unamortized discounts. The December 31, 2006 amount includes a liability of $29.1 million related to fair value hedges and a net $4.4 million in unamortized discounts.
     Letters of credit
          At December 31, 2007, we had $1.1 million of standby letters outstanding under Duncan Energy Partners’ Revolving Credit Facility. At December 31, 2006, we had $49.9 million in standby letters of credit outstanding, all of which were issued under EPO’s Multi-Year Revolving Credit Facility. As of February 1, 2008, our standby letters of credit outstanding were $1.1 million under Duncan Energy Partners’ Revolving Credit Facility.
     Parent-Subsidiary guarantor relationships
          We act as guarantor of the debt obligations of EPO with the exception of the Dixie revolving credit facility and the senior subordinated notes we assumed in connection with the GulfTerra Merger. If EPO were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. We do not act as guarantor of the debt obligations of Duncan Energy Partners.

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          EPO’s senior indebtedness is structurally subordinated to and ranks junior in right of payment to the indebtedness of GulfTerra and Dixie. This subordination feature exists only to the extent that the repayment of debt incurred by GulfTerra and Dixie is dependent upon the assets and operations of these two entities. The Dixie revolving credit facility is an unsecured obligation of Dixie (of which we own 74.2% of its capital stock). The senior subordinated notes of GulfTerra are unsecured obligations of GulfTerra (of which we own 100% of its limited and general partnership interests).
     EPO’s debt obligations
          Multi-Year Revolving Credit Facility. In November 2007, EPO executed an amended and restated Multi-Year Revolving Credit Facility totaling $1.75 billion, which replaced an existing $1.25 billion multi-year revolving credit agreement. Amounts borrowed under the amended and restated credit agreement mature in November 2012, although EPO is permitted, 30 to 60 days before the maturity date in effect, to convert the principal balance of the revolving loans then outstanding into a non-revolving, one-year term loan (the “term-out option”). There is no sublimit on the amount of standby letters of credit that can be outstanding under the amended facility. EPO’s borrowings under this agreement are unsecured general obligations that are non-recourse to EPGP. We have guaranteed repayment of amounts due under this revolving credit agreement through an unsecured guarantee.
          As defined by the credit agreement, variable interest rates charged under this facility bear interest at a Eurodollar rate plus an applicable margin. In addition, EPO is required to pay a quarterly facility fee on each lender’s commitment irrespective of commitment usage.
          The applicable margins will be increased by 0.100% per annum for each day that the total outstanding loans and letter of credit obligations under the facility exceeds fifty percent of the total lender commitments. Also, upon the conversion of the revolving loans to term loans pursuant to the term-out option described above, the applicable margin will increase by 0.125% per annum and, if immediately prior to such conversion, the total amount of outstanding loans and letter of credit obligations under the facility exceeds fifty percent of the total lender commitments, the applicable margin with respect to the term loans will increase by an additional 0.10% per annum.
          EPO may increase the amount that may be borrowed under the facility, without the consent of the lenders, by an amount not exceeding $500.0 million by adding to the facility one or more new lenders and/or requesting that the commitments of existing lenders be increased, although none of the existing lenders has agreed to or is obligated to increase its existing commitment. EPO may request unlimited one-year extensions of the maturity date by delivering a written request to the administrative agent, but any such extension shall be effective only if consented to by the required lenders in their sole discretion.
          The Multi-Year Revolving Credit Facility contains various covenants related to EPO’s ability to incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; and make certain investments. The loan agreement also requires EPO to satisfy certain financial covenants at the end of each fiscal quarter. The credit agreement also restricts EPO’s ability to pay cash distributions to us if a default or an event of default (as defined in the credit agreement) has occurred and is continuing at the time such distribution is scheduled to be paid.
          Pascagoula MBFC Loan. In connection with the construction of our Pascagoula, Mississippi natural gas processing plant in 2000, EPO entered into a ten-year fixed-rate loan with the Mississippi Business Finance Corporation (“MBFC”). This loan is subject to a make-whole redemption right and is guaranteed by us through an unsecured and unsubordinated guarantee. The Pascagoula MBFC Loan contains certain covenants including the maintenance of appropriate levels of insurance on the Pascagoula facility.
          The indenture agreement for this loan contains an acceleration clause whereby if EPO’s credit rating by Moody’s declines below Baa3 in combination with our credit rating at Standard & Poor’s declining below BBB-, the $54 million principal balance of this loan, together with all accrued and unpaid interest, would become immediately due and payable 120 days following such event. If such an event

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occurred, we would have to either redeem the Pascagoula MBFC Loan or provide an alternative credit agreement to support our obligation under this loan.
          Senior Notes B through L. These fixed-rate notes are unsecured obligations of EPO and rank equally with its existing and future unsecured and unsubordinated indebtedness. They are senior to any future subordinated indebtedness. EPO’s borrowings under these notes are non-recourse to EPGP. We have guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. Our guarantee of such notes is non-recourse to EPGP. The Senior Notes are subject to make-whole redemption rights and were issued under indentures containing certain covenants, which generally restrict EPO’s ability, with certain exceptions, to incur debt secured by liens and engage in sale and leaseback transactions.
          EPO used net proceeds from its issuance of Senior Notes L to temporarily reduce indebtedness outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. In October 2007, EPO used borrowing capacity under its Multi-Year Revolving Credit Facility to repay its $500.0 million Senior Notes E.
          Petal GO Zone Bonds. In August 2007, Petal borrowed $57.5 million from the MBFC pursuant to a loan agreement and promissory note between Petal and the MBFC to pay a portion of the costs of certain natural gas storage facilities located in Petal, Mississippi.  The promissory note between Petal and MBFC is guaranteed by EPO and supported by a letter of credit issued by Petal. On the same date, the MBFC issued $57.5 million in Gulf Opportunity Zone Tax-Exempt (“GO Zone”) bonds to various third parties. A portion of the GO Zone bond proceeds are being held by a third party trustee and reflected as a component of other assets on our balance sheet. The remaining proceeds held by the trustee will be released to us as we spend capital to complete the construction of the natural gas storage facilities. At December 31, 2007, $17.9 million of the GO Zone bond proceeds remained held by the third party trustee.  The promissory note and the GO Zone bonds have identical terms including floating interest rates and maturities of twenty-seven years.  The bonds and the associated tax incentives are authorized under the Mississippi Business Finance Act and the Gulf Opportunity Zone Act of 2005. 
          Petal MBFC Loan. In August 2007, Petal Gas Storage L.L.C. (“Petal”), a wholly owned subsidiary of EPO, entered into a loan agreement and a promissory note with the MBFC under which Petal may borrow up to $29.5 million.  On the same date, the MBFC issued taxable bonds to EPO in the maximum amount of $29.5 million.  As of December 31, 2007, there was $8.9 million outstanding under the loan and the bonds.  EPO will make advances on the bonds to the MBFC and the MBFC will in turn make identical advances to Petal under the promissory note. The promissory note and the taxable bonds have identical terms including fixed interest rates of 5.90% and maturities of fifteen years.  The bonds and the associated tax incentives are authorized under the Mississippi Business Finance Act.  Petal may prepay on the promissory note without penalty, and thus cause the bonds to be redeemed, any time after one year from their date of issue.  The loan and bonds are netted in preparing our consolidated balance sheet, as well the related interest expense and income amounts are netted in preparing our consolidated income statement.
          Junior Notes A. In the third quarter of 2006, EPO sold $550.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due 2066 (“Junior Notes A”). EPO used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. EPO’s payment obligations under Junior Notes A are subordinated to all of its current and future senior indebtedness (as defined in the related indenture agreement). We guaranteed EPO’s repayment of amounts due under Junior Notes A through an unsecured and subordinated guarantee.
          The indenture agreement governing Junior Notes A allows EPO to defer interest payments on one or more occasions for up to ten consecutive years, subject to certain conditions. The indenture agreement also provides that, unless (i) all deferred interest on Junior Notes A has been paid in full as of the most recent interest payment date, (ii) no event of default under the indenture agreement has occurred and is continuing and (iii) we are not in default of our obligations under related guarantee agreements, neither we nor EPO cannot declare or make any distributions to any of our respective equity securities or make any

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payments on indebtedness or other obligations that rank pari passu with or are subordinated to the Junior Notes A.
          The Junior Notes A bear interest at a fixed annual rate of 8.375% from July 2006 to August 2016, payable semi-annually in arrears in February and August of each year, which commenced in February 2007. After August 2016, the Junior Notes A will bear variable rate interest at an annual rate equal to the 3-month LIBOR rate for the related interest period plus 3.708%, payable quarterly in arrears in February, May, August and November of each year commencing in November 2016. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to the certain provisions. The Junior Notes A mature in August 2066 and are not redeemable by EPO prior to August 2016 without payment of a make-whole premium.
          In connection with the issuance of Junior Notes A, EPO entered into a Replacement Capital Covenant in favor of the covered debt holders (as defined in the underlying documents) pursuant to which EPO agreed for the benefit of such debt holders that it would not redeem or repurchase such junior notes unless such redemption or repurchase is made using proceeds from the of issuance of certain securities.
          Junior Notes B. EPO sold $700 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due January 2068 (“Junior Notes B”) during the second quarter of 2007. EPO used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Multi-Year Revolving Credit Facility and for general partnership purposes. EPO’s payment obligations under Junior Notes B are subordinated to all of its current and future senior indebtedness (as defined in the Indenture Agreement). We have guaranteed repayment of amounts due under Junior Notes B through an unsecured and subordinated guarantee.
          The indenture agreement governing Junior Notes B allows EPO to defer interest payments on one or more occasions for up to ten consecutive years subject to certain conditions. During any period in which interest payments are deferred and subject to certain exceptions, neither we nor EPO can declare or make any distributions to any of our respective equity securities or make any payments on indebtedness or other obligations that rank pari passu with or are subordinate to Junior Notes B. Junior Notes B rank pari passu with Junior Notes A.
          The Junior Notes B will bear interest at a fixed annual rate of 7.034% through January 15, 2018, payable semi-annually in arrears in January and July of each year, commencing in January 2008. After January 2018, the Junior Notes B will bear variable rate interest at the greater of (1) the sum of the 3-month LIBOR for the related interest period plus a spread of 268 basis points or (2) 7.034% per annum, payable quarterly in arrears in January, April, July and October of each year commencing in April 2018. Interest payments may be deferred on a cumulative basis for up to ten consecutive years, subject to certain provisions. The Junior Notes B mature in January 2068 and are not redeemable by EPO prior to January 2018 without payment of a make-whole premium.
          In connection with the issuance of Junior Notes B, we and EPO entered into a Replacement Capital Covenant in favor of the covered debt holders (as named therein) pursuant to which we and EPO agreed for the benefit of such debt holders that neither we nor EPO would redeem or repurchase such junior notes on or before January 15, 2038, unless such redemption or repurchase is made from the proceeds of issuance of certain securities.
     Duncan Energy Partners’ debt obligation
          We consolidate the debt of Duncan Energy Partners with that of our own; however, we do not have the obligation to make interest payments or debt payments with respect to the debt of Duncan Energy Partners.
          Duncan Energy Partners entered into a $300.0 million revolving credit facility, all of which may be used for letters of credit, with a $30.0 million sublimit for Swingline loans. Letters of credit outstanding under this facility reduce the amount available for borrowings. At the closing of its initial public offering,

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Duncan Energy Partners made its initial borrowing of $200.0 million under the facility to fund a $198.9 million cash distribution to EPO and the remainder to pay debt issuance costs. At December 31, 2007, the principal balance outstanding under this facility was $200.0 million.
          This credit facility matures in February 2011 and will be used by Duncan Energy Partners in the future to fund working capital and other capital requirements and for general partnership purposes. Duncan Energy Partners may make up to two requests for one-year extensions of the maturity date (subject to certain restrictions). The revolving credit facility is available to pay distributions upon the initial contribution of assets to Duncan Energy Partners, fund working capital, make acquisitions and provide payment for general purposes. Duncan Energy Partners can increase the revolving credit facility, without consent of the lenders, by an amount not to exceed $150.0 million by adding to the facility one or more new lenders and/or increasing the commitments of existing lenders. No existing lender is required to increase its commitment, unless it agrees to do so in its sole discretion.
          This revolving credit facility offers the following unsecured loans, each having different interest requirements: (i) LIBOR loans bear interest at a rate per annum equal to LIBOR plus the applicable LIBOR margin (as defined in the credit agreement), (ii) Base Rate loans bear interest at a rate per annum equal to the higher of (a) the rate of interest publicly announced by the administrative agent, Wachovia Bank, National Association, as its Base Rate and (b) 0.5% per annum above the Federal Funds Rate in effect on such date and (iii) Swingline loans bear interest at a rate per annum equal to LIBOR plus an applicable LIBOR margin.
          The Duncan Energy Partners’ credit facility contains certain financial and other customary covenants. Also, if an event of default exists under the credit agreement, the lenders will be able to accelerate the maturity date of amounts borrowed under the credit agreement and exercise other rights and remedies.
     Dixie Revolving Credit Facility
          As a result of acquiring a controlling interest in Dixie in February 2005, we began consolidating the financial statements of Dixie with those of our own. In accordance with GAAP, we consolidate the debt of Dixie with that of our own; however we do not have the obligation to make interest or debt payments with respect to Dixie’s debt. Dixie’s debt obligations consist of a senior, unsecured revolving credit facility having a borrowing capacity of $28.0 million. The maturity date of this facility was extended from June 2007 to June 2010 in August 2006.
          As defined in the Dixie credit agreement, variable interest rates charged under this facility generally bear interest, at our election at the time of each borrowing, at either (i) a Eurodollar rate plus an applicable margin or (ii) the greater of (a) the Prime Rate or (b) the Federal Funds Rate plus 1/2%.
          The credit agreement contains various covenants related to Dixie’s ability to incur certain indebtedness; grant certain liens; enter into merger transactions; and make certain investments. The loan agreement also requires Dixie to satisfy a minimum net worth financial covenant. The revolving credit agreement restricts Dixie’s ability to pay cash dividends to us and its other stockholders if a default or an event of default (as defined in the credit agreement) has occurred and its continuing at the time such dividend is scheduled to be paid.
     Canadian Debt Obligations
          In May 2007, Canadian Enterprise Gas Products, Ltd. (“Canadian Enterprise”), a wholly-owned subsidiary of EPO, entered into a $30.0 million Canadian revolving credit facility with The Bank of Nova Scotia. The credit facility, which includes the issuance of letters of credit, matures in October 2011. Letters of credit outstanding under this facility reduce the amount available for borrowings.
          Borrowings may be made in Canadian or U.S. dollars. Canadian denominated borrowings may be comprised of Canadian Prime Rate (“CPR”) loans or Bankers’ Acceptances and U.S. denominated

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borrowings may be comprised of Alternative Base Rate (“ABR”) or Eurodollar loans, each having different interest rate requirements. CPR loans bear interest at a rate determined by reference to the Canadian Prime Rate. ABR loans bear interest at a rate determined by reference to an alternative base rate as defined in the credit agreement. Eurodollar loans bear interest at a rate determined by the LIBOR plus an applicable rate as defined in the credit agreement. Bankers’ Acceptances carry interest at the rate for Canadian bankers’ acceptances plus an applicable rate as defined in the credit agreement.
          The credit facility contains customary covenants and events of default. The restrictive covenants limit Canadian Enterprise from materially changing the nature of its business or operations, dissolving, or completing mergers. A continuing event of default would accelerate the maturity of amounts borrowed under the credit facility. The obligations under the credit facility are guaranteed by EPO. As of December 31, 2007, there were no debt obligations outstanding under this credit facility.
     Covenants
          We are in compliance with the covenants of our consolidated debt agreements at December 31, 2007 and 2006.
     Information regarding variable interest rates paid
          The following table shows the range of interest rates paid and weighted-average interest rate paid on our consolidated variable-rate debt obligations during the year ended December 31, 2007.
             
    Range of   Weighted-average
    interest rates   interest rate
    paid   paid
     
EPO’s Multi-Year Revolving Credit Facility
  5.10% to 8.25%     5.78 %
Duncan Energy Partners’ Revolving Credit Facility
  5.52% to 6.42%     6.23 %
Dixie Revolving Credit Facility
  5.50% to 5.67%     5.63 %
Canadian Enterprise Revolving Credit Facility
  5.01% to 5.82%     5.68 %
Petal GO Zone Bonds
  3.11% to 4.15%     3.56 %
     Consolidated debt maturity table
          The following table presents the scheduled maturities of principal amounts of our debt obligations for the next five years and in total thereafter.
         
2008
  $  
2009
    500,000  
2010
    591,840  
2011
    650,000  
2012
    697,160  
Thereafter
    4,457,500  
 
     
Total scheduled principal payments
  $ 6,896,500  
 
     
          In accordance with SFAS 6, long-term and current maturities of debt reflect the classification of such obligations at December 31, 2006. With respect to the $500.0 million in principal that was due under Senior Notes E in October 2007, EPO repaid this note in October 2007 using cash and available credit capacity under its Multi-Year Revolving Credit Facility. The preceding table and our Consolidated Balance Sheet at December 31, 2006 reflect this ability to refinance.

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     Debt Obligations of Unconsolidated Affiliates
          We have two unconsolidated affiliates with long-term debt obligations. The following table shows (i) our ownership interest in each entity at December 31, 2007, (ii) total debt of each unconsolidated affiliate at December 31, 2007 (on a 100% basis to the affiliate) and (iii) the corresponding scheduled maturities of such debt.
                                                                 
    Our             Scheduled Maturities of Debt
    Ownership                                                   After
    Interest   Total   2008   2009   2010   2011   2012   2012
     
Poseidon
    36 %   $ 91,000     $     $     $     $ 91,000     $     $  
Evangeline
    49.5 %     20,650       5,000       5,000       10,650                    
             
Total
          $ 111,650     $ 5,000     $ 5,000     $ 10,650     $ 91,000     $     $  
             
          The credit agreements of our unconsolidated affiliates contain various affirmative and negative covenants, including financial covenants. These businesses were in compliance with such covenants at December 31, 2007. The credit agreements of our unconsolidated affiliates restrict their ability to pay cash dividends if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend is scheduled to be paid. Cameron Highway repaid its debt obligations during the second quarter of 2007 using pro rata capital contributions from EPO and its joint venture partner in Cameron Highway.
          The following information summarizes significant terms of the debt obligations of our unconsolidated affiliates at December 31, 2007:
          Poseidon. Poseidon has $91.0 million outstanding under its $150.0 million revolving credit facility that matures in May 2011. Interest rates charged under this revolving credit facility are variable and depend on the ratio of Poseidon’s total debt to its earnings before interest, taxes, depreciation and amortization. This credit agreement is secured by substantially all of Poseidon’s assets. The variable interest rates charged on this debt at December 31, 2007 and 2006 were 6.62% and 6.68%, respectively.
          Evangeline. At December 31, 2007, short and long-term debt for Evangeline consisted of (i) $13.2 million in principal amount of 9.90% fixed-rate Series B senior secured notes due December 2010 and (ii) a $7.5 million subordinated note payable. The Series B senior secured notes are collateralized by Evangeline’s property, plant and equipment; proceeds from a gas sales contract; and by a debt service reserve requirement. Scheduled principal repayments on the Series B notes are $5.0 million annually through 2009 with a final repayment in 2010 of approximately $3.2 million. The trust indenture governing the Series B notes contains covenants such as requirements to maintain certain financial ratios.
          Evangeline incurred the subordinated note payable as a result of its acquisition of a contract-based intangible asset in the 1990s. This note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the note until such time as the Series B noteholders are either fully cash secured through debt service accounts or have been completely repaid. Variable rate interest accrues on the subordinated note at a Eurodollar rate plus 1/2%. The variable interest rates charged on this note at December 31, 2007 and 2006 were 5.88% and 6.08%, respectively. Accrued interest payable related to the subordinated note was $9.1 million and $7.9 million at December 31, 2007 and 2006, respectively.
Note 15. Partners’ Equity and Distributions
          Our common units represent limited partner interests, which give the holders thereof the right to participate in distributions and to exercise the other rights or privileges available to them under our Fifth Amended and Restated Agreement of Limited Partnership (together with all amendments thereto, the “Partnership Agreement”). We are managed by our general partner, EPGP.

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          In accordance with the Partnership Agreement, capital accounts are maintained for our general partner and limited partners. The capital account provisions of our Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to the equity accounts reflected under GAAP in our consolidated financial statements.
          Our Partnership Agreement sets forth the calculation to be used in determining the amount and priority of cash distributions that our limited partners and general partner will receive. The Partnership Agreement also contains provisions for the allocation of net earnings and losses to our limited partners and general partner. For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall be allocated among the partners in accordance with their respective percentage interests. Normal income and loss allocations according to percentage interests are done only after giving effect to priority earnings allocations in an amount equal to incentive cash distributions allocated to our general partner.
          In August 2005, we revised our Partnership Agreement to allow EPGP, at its discretion, to elect not to make its proportionate capital contributions to us in connection with our issuance of limited partner interests, in which case its 2% general partner interest would be proportionately reduced. At the time of such offerings, EPGP has historically contributed cash to us to maintain its 2% general partner interest. EPGP made such cash contributions to us during the years ended December 31, 2007 and 2006. If EPGP exercises this option in the future, the amount of earnings we allocate to it and the cash distributions it receives from us will be reduced accordingly. If this occurs, EPGP can, under certain conditions, restore its full 2% general partner interest by making additional cash contributions to us.
     Equity offerings and registration statements
          In general, the Partnership Agreement authorizes us to issue an unlimited number of additional limited partner interests and other equity securities for such consideration and on such terms and conditions as may be established by EPGP in its sole discretion (subject, under certain circumstances, to the approval of our unitholders).
          In August 2007, we filed a universal shelf registration statement with the SEC that allows us to issue an unlimited amount of debt and equity securities.
          During 2003, we instituted a distribution reinvestment plan (“DRIP”). In April 2007, we filed a registration statement with the SEC authorizing the issuance of up to 25,000,000 common units in connection with the DRIP. The DRIP provides unitholders of record and beneficial owners of our common units a voluntary means by which they can increase the number of common units they own by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional common units. A total of 16,102,737 common units have been issued under this registration statement through December 31, 2007.
          We also have a registration statement on file related to our employee unit purchase plan, under which we can issue up to 1,200,000 common units. Under this plan, employees of EPCO can purchase our common units at a 10% discount through payroll deductions. A total of 495,661 common units have been issued to employees under this plan through December 31, 2007.
          The following table reflects the number of common units issued and the net proceeds received from underwritten and other common unit offerings completed during the years ended December 31, 2007, 2006 and 2005:

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    Net Proceeds from Sale of Common Units
    Number of   Contributed   Contributed by   Total
    common units   by Limited   General   Net
    issued   Partners   Partner   Proceeds
     
Fiscal 2005:
                               
Underwritten offerings
    21,250,000     $ 544,347     $ 11,109     $ 555,456  
Other offerings, primarily DRIP
    2,729,740       68,269       1,393       69,662  
     
Total 2005
    23,979,740     $ 612,616     $ 12,502     $ 625,118  
     
Fiscal 2006:
                               
Underwritten offerings
    31,050,000     $ 735,819     $ 15,003     $ 750,822  
Other offerings, primarily DRIP
    3,774,649       95,006       1,940       96,946  
     
Total 2006
    34,824,649     $ 830,825     $ 16,943     $ 847,768  
     
Fiscal 2007:
                               
Other offerings, primarily DRIP
    2,056,615     $ 60,445     $ 1,232     $ 61,677  
     
Total 2007
    2,056,615     $ 60,445     $ 1,232     $ 61,677  
     
          Other offerings primarily represent the issuance of common units under our distribution reinvestment plan. Net proceeds received from our underwritten offerings completed during 2005 were generally used to repay an interim credit facility related to the GulfTerra Merger and to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility. Net proceeds from our other offerings were used for general partnership purposes.
          Net proceeds received from our underwritten and other offerings completed during 2006 were used to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.
          Net proceeds received from our other offerings completed during 2007 were used to temporarily reduce borrowings outstanding under EPO’s Multi-Year Revolving Credit Facility and for general partnership purposes.
     Summary of Changes in Outstanding Units
          The following table summarizes changes in our outstanding units since December 31, 2004:
                         
            Restricted    
    Common   Common   Treasury
    Units   Units   Units
     
Balance, December 31, 2004
    364,297,340       488,525       427,200  
Units issued in connection with underwritten offerings
    21,250,000              
Units issued in connection with other offerings
    2,729,740              
Units issued in connection with equity-based awards
    826,000       362,011        
Forfeiture of restricted units
          (92,448 )      
Conversion of restricted units to common units
    6,484       (6,484 )      
Cancellation of treasury units
                (427,200 )
     
Balance, December 31, 2005
    389,109,564       751,604        
Units issued in connection with underwritten offerings
    31,050,000              
Units issued in connection with other offerings
    3,774,649              
Units issued in connection with equity-based awards
    211,000       466,400        
Forfeiture of restricted units
          (70,631 )      
Conversion of restricted units to common units
    42,136       (42,136 )      
Units issued in connection with Encinal acquisition
    7,115,844              
     
Balance, December 31, 2006
    431,303,193       1,105,237        
Units issued in connection with other offerings
    2,056,615              
Units issued in connection with equity-based awards
    244,071       738,040        
Forfeiture or settlement of restricted units
          (149,853 )      
Conversion of restricted units to common units
    4,884       (4,884 )      
     
Balance, December 31, 2007
    433,608,763       1,688,540        
     

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          Treasury Units. In 2000, we and a consolidated trust (the “1999 Trust”) were authorized by EPGP to repurchase up to 2,000,000 publicly-held common units under an announced buy-back program. The repurchases would be made during periods of temporary market weakness at price levels that would be accretive to our remaining unitholders. After deducting for repurchases under the program in prior periods, we and the 1999 Trust could repurchase up to 618,400 common units at December 31, 2005. We cancelled our 427,200 treasury units in 2005.
Summary of Changes in Limited Partners’ Equity
          The following table details the changes in limited partners’ equity since December 31, 2004:
                         
            Restricted        
    Common     Common        
    units     units     Total  
     
Balance, December 31, 2004
  $ 5,204,940     $ 12,327     $ 5,217,267  
Net income
    347,948       564       348,512  
Operating leases paid by EPCO
    2,067       3       2,070  
Cash distributions to partners
    (629,629 )     (931 )     (630,560 )
Unit option reimbursements to EPCO
    (9,199 )           (9,199 )
Net proceeds from sales of common units
    612,616             612,616  
Proceeds from exercise of unit options
    21,374             21,374  
Issuance of restricted units
          9,478       9,478  
Vesting of restricted units
    143       (143 )      
Forfeiture of restricted units
          (2,663 )     (2,663 )
Amortization of equity-based awards
    1,355       3       1,358  
Cancellation of treasury units
    (8,915 )           (8,915 )
         
Balance, December 31, 2005
    5,542,700       18,638       5,561,338  
Net income
    502,969       1,187       504,156  
Operating leases paid by EPCO
    2,062       5       2,067  
Cash distributions to partners
    (738,004 )     (1,628 )     (739,632 )
Unit option reimbursements to EPCO
    (1,818 )           (1,818 )
Net proceeds from sales of common units
    830,825             830,825  
Common units issued in connection with Encinal acquisition
    181,112             181,112  
Proceeds from exercise of unit options
    5,601               5,601  
Amortization of equity-based awards
    2,209       6,073       8,282  
Change in accounting method for equity Awards (see Note 5)
    (896 )     (14,919 )     (15,815 )
Acquisition-related disbursement of cash
    (6,183 )     (16 )     (6,199 )
     
Balance, December 31, 2006
    6,320,577       9,340       6,329,917  
Net income
    416,323       1,405       417,728  
Operating leases paid by EPCO
    2,056       7       2,063  
Cash distributions to partners
    (831,155 )     (2,638 )     (833,793 )
Unit option reimbursements to EPCO
    (2,999 )           (2,999 )
Net proceeds from sales of common units
    60,445             60,445  
Proceeds from exercise of unit options
    7,549             7,549  
Repurchase of restricted units and options
    (512 )     (1,056 )     (1,568 )
Amortization of equity-based awards
    4,663       8,890       13,553  
         
Balance, December 31, 2007
  $ 5,976,947     $ 15,948     $ 5,992,895  
         
          In October 2006, we acquired all of the capital stock of an affiliated NGL marketing company located in Canada from EPCO and Dan L. Duncan for $17.7 million in cash. The amount we paid for this business exceeded the carrying values of the assets acquired and liabilities assumed from this related party (which is under common control with us) by $6.3 million, of which $6.2 million was allocated to limited partners and $0.1 million to our general partner. The excess of the acquisition price over the net book value of this business at the time of acquisition is treated as a deemed distribution to our owners and presented as an “Acquisition-related disbursement of cash” in our Statement of Partners’ Equity for the year ended December 31, 2006. The total purchase price is a component of “Cash used for business combinations” as presented in our Statement of Consolidated Cash Flows for the year ended December 31, 2006 (see Note 12).

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Distributions to Partners
          The percentage interest of EPGP in our quarterly cash distributions is increased after certain specified target levels of quarterly distribution rates are met. At current distribution rates, we are in the highest tier of such incentive targets. EPGP’s quarterly incentive distribution thresholds are as follows:
  §   2% of quarterly cash distributions up to $0.253 per unit;
 
  §   15% of quarterly cash distributions from $0.253 per unit up to $0.3085 per unit; and
 
  §   25% of quarterly cash distributions that exceed $0.3085 per unit.
          We paid incentive distributions of $107.4 million, $86.7 million and $63.9 million to EPGP during the years ended December 31, 2007, 2006 and 2005, respectively.
          The following table presents our declared quarterly cash distribution rates per unit since the first quarter of 2006 and the related record and distribution payment dates. The quarterly cash distribution rates per unit correspond to the fiscal quarters indicated. Actual cash distributions are paid within 45 days after the end of such fiscal quarter.
                         
    Distribution   Record   Payment
    per Unit   Date   Date
     
2006
                       
1st Quarter
  $ 0.4450     Apr. 28, 2006   May 10, 2006
2nd Quarter
  $ 0.4525     Jul. 31, 2006   Aug. 10, 2006
3rd Quarter
  $ 0.4600     Oct. 31, 2006   Nov. 8, 2006
4th Quarter
  $ 0.4675     Jan. 31, 2007   Feb. 8, 2007
2007
                       
1st Quarter
  $ 0.4750     Apr. 30, 2007   May 10, 2007
2nd Quarter
  $ 0.4825     Jul. 31, 2007   Aug. 9, 2007
3rd Quarter
  $ 0.4900     Oct. 31, 2007   Nov. 8, 2007
4th Quarter
  $ 0.5000     Jan. 31, 2008   Feb. 7, 2008
Accumulated Other Comprehensive Income
          The following table presents the components of accumulated other comprehensive income at the dates indicated:
                 
    At December 31,
    2007   2006
     
Commodity financial instruments (1)
  $ (21,619 )   $ (3,622 )  
Interest rate financial instruments (1)
    34,980       26,034  
Foreign currency hedges (1)
    1,308        
Foreign currency translation adjustment (1)
    1,200       (807 )
Pension and postretirement benefit plans (2)
    588       (464 )
     
Total accumulated other comprehensive income
  $ 16,457     $ 21,141  
       
 
(1)   See Note 2 for additional information regarding these components of accumulated other comprehensive income.
 
(2)   See Note 6 for additional information regarding pension and postretirement benefit plans.
Note 16. Business Segments
          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.

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          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 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.
          Segment revenues include intersegment and intrasegment transactions, which are generally based on transactions made at market-related rates. Our consolidated revenues reflect the elimination of intercompany (both intersegment and intrasegment) transactions.
          We include equity earnings from unconsolidated affiliates in our measurement of segment gross operating margin and operating income. Our equity investments with industry partners are a vital component of our business strategy. They are a means by which we conduct our operations to align our interests with those of our customers and/or suppliers. This method of operation enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what we could accomplish on a stand-alone basis. Many of these businesses perform supporting or complementary roles to our other business operations.
          Our integrated midstream energy asset system (including the midstream energy assets of our equity method investees) provides services to producers and consumers of natural gas, NGLs, crude oil and certain petrochemicals. In general, hydrocarbons enter our asset system in a number of ways, such as an offshore natural gas or crude oil pipeline, an offshore platform, a natural gas processing plant, an onshore natural gas gathering pipeline, an NGL fractionator, an NGL storage facility, or an NGL transportation or distribution pipeline.
          Many of our equity investees are included within our integrated midstream asset system. For example, we have ownership interests in several offshore natural gas and crude oil pipelines. Other examples include our use of the Promix NGL fractionator to process mixed NGLs extracted by our gas plants. The fractionated NGLs we receive from Promix can then be sold in our NGL marketing activities. Given the integral nature of our equity method investees to our operations, we believe the presentation of earnings from such investees as a component of gross operating margin and operating income is meaningful and appropriate.
          Historically, substantially all of our consolidated revenues were earned in the United States and derived from a wide customer base. The majority of our plant-based operations are located in Texas, Louisiana, Mississippi, New Mexico and Wyoming. Our natural gas, NGL and crude oil pipelines are located in a number of regions of the United States including (i) the Gulf of Mexico offshore Texas and Louisiana; (ii) the south and southeastern United States (primarily in Texas, Louisiana, Mississippi and Alabama); and (iii) certain regions of the central and western United States, including the Rocky Mountains. Our marketing activities are headquartered in Houston, Texas and serve customers in a number of regions of the United States including the Gulf Coast, West Coast and Mid-Continent areas.
          Consolidated property, plant and equipment and investments in and advances to unconsolidated affiliates are assigned to each segment on the basis of each asset’s or investment’s principal operations.

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The principal reconciling difference between consolidated property, plant and equipment and the total value of segment assets is construction-in-progress. Segment assets represent the net book carrying value of facilities and other assets that contribute to gross operating margin of that particular segment. Since assets under construction generally do not contribute to segment gross operating margin, such assets are excluded from segment asset totals until they are placed in service. Consolidated intangible assets and goodwill are assigned to each segment based on the classification of the assets to which they relate.
          We consolidate the financial statements of Duncan Energy Partners with those of our own. As a result, our consolidated gross operating margin amounts include the gross operating margin amounts of Duncan Energy Partners on a 100% basis.
          The following table shows our measurement of total segment gross operating margin for the periods indicated:
                             
        For the Year Ended December 31,
        2007   2006   2005
         
Revenues (1)  
 
  $ 16,950,125     $ 13,990,969     $ 12,256,959  
Less:  
Operating costs and expenses (1)
    (16,009,051 )     (13,089,091 )     (11,546,225 )
Add:  
Equity in income of unconsolidated affiliates (1)
    29,658       21,565       14,548  
   
Depreciation, amortization and accretion in operating costs and expenses (2)
    513,840       440,256       413,441  
   
Operating lease expenses paid by EPCO (2)
    2,105       2,109       2,112  
   
Loss (gain) on sale of assets in operating costs and expenses (2)
    5,391       (3,359 )     (4,488 )
         
Total segment gross operating margin   $ 1,492,068     $ 1,362,449     $ 1,136,347  
         
 
(1)   These amounts are taken from our Statements of Consolidated Operations.
 
(2)   These non-cash expenses are taken from the operating activities section of our Statements of Consolidated Cash Flows.
          A reconciliation of our total segment gross operating margin to operating income and income before provision for income taxes, minority interest and the cumulative effect of changes in accounting principles follows:
                                 
            For the Year Ended December 31,
            2007   2006   2005
Total segment gross operating margin   $ 1,492,068     $ 1,362,449     $ 1,136,347  
Adjustments to reconcile total segment gross operating margin to operating income:                        
       
Depreciation, amortization and accretion in operating costs and expenses
    (513,840 )     (440,256 )     (413,441 )
       
Operating lease expense paid by EPCO
    (2,105 )     (2,109 )     (2,112 )
       
Gain (loss) on sale of assets in operating costs and expenses
    (5,391 )     3,359       4,488  
       
General and administrative costs
    (87,695 )     (63,391 )     (62,266 )
             
Consolidated operating income     883,037       860,052       663,016  
       
Other expense, net
    (303,463 )     (229,967 )     (225,178 )
             
Income before provision for income taxes, minority interest and cumulative effect of change in accounting principle
  $ 579,574     $ 630,085     $ 437,838  
             

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          Information by segment, together with reconciliations to our consolidated totals, is presented in the following table:
                                                 
    Reportable Segments        
            Onshore                    
    NGL   Natural Gas   Offshore           Adjustments    
    Pipelines   Pipelines   Pipelines   Petrochemical   and   Consolidated
    & Services   & Services   & Services   Services   Eliminations   Totals
     
Revenues from third parties:
                                               
Year ended December 31, 2007
  $ 12,101,715     $ 1,788,219     $ 222,642     $ 2,184,833     $     $ 16,297,409  
Year ended December 31, 2006
    10,079,534       1,407,872       144,065       1,956,268             13,587,739  
Year ended December 31, 2005
    9,006,730       1,185,577       110,100       1,587,037             11,889,444  
Revenues from related parties:
                                               
Year ended December 31, 2007
    369,654       281,876       1,169       17             652,716  
Year ended December 31, 2006
    110,409       291,023       1,798                   403,230  
Year ended December 31, 2005
    16,689       350,025       696       105             367,515  
Intersegment and intrasegment revenues:
                                               
Year ended December 31, 2007
    5,346,571       191,741       1,959       514,852       (6,055,123 )      
Year ended December 31, 2006
    4,131,776       113,132       1,679       383,754       (4,630,341 )      
Year ended December 31, 2005
    3,334,763       41,576       1,353       346,458       (3,724,150 )      
Total revenues:
                                               
Year ended December 31, 2007
    17,817,940       2,261,836       225,770       2,699,702       (6,055,123 )     16,950,125  
Year ended December 31, 2006
    14,321,719       1,812,027       147,542       2,340,022       (4,630,341 )     13,990,969  
Year ended December 31, 2005
    12,358,182       1,577,178       112,149       1,933,600       (3,724,150 )     12,256,959  
Equity in income of unconsolidated affiliates:
                                               
Year ended December 31, 2007
    6,031       9,540       12,628       1,459             29,658  
Year ended December 31, 2006
    5,715       2,872       11,909       1,069             21,565  
Year ended December 31, 2005
    5,553       2,384       6,125       486             14,548  
Gross operating margin by individual
business segment and in total:
                                               
Year ended December 31, 2007
    812,521       335,683       171,551       172,313             1,492,068  
Year ended December 31, 2006
    752,548       333,399       103,407       173,095             1,362,449  
Year ended December 31, 2005
    579,706       353,076       77,505       126,060             1,136,347  
Segment assets:
                                               
At December 31, 2007
    4,570,555       3,702,297       1,452,568       687,856       1,173,988       11,587,264  
At December 31, 2006
    3,249,486       3,611,974       734,659       502,345       1,734,083       9,832,547  
Investments in and advances to
unconsolidated affiliates (see Note 11):
                                               
At December 31, 2007
    117,089       239,327       484,588       17,335             858,339  
At December 31, 2006
    111,229       124,591       310,136       18,603             564,559  
Intangible Assets (see Note 13):
                                               
At December 31, 2007
    373,071       354,152       133,058       56,719             917,000  
At December 31, 2006
    417,950       386,149       152,376       47,480             1,003,955  
Goodwill (see Note 13):
                                               
At December 31, 2007
    153,706       282,121       82,135       73,690             591,652  
At December 31, 2006
    152,595       282,121       82,135       73,690             590,541  
          In general, our historical operating results and/or financial position have been affected by business combinations and other acquisitions. The operating results of entities and assets we acquire are included in our financial results prospectively from their purchase dates.

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Note 17. Related Party Transactions
          The following table summarizes our related party transactions for the periods indicated.
                         
    For the Year Ended December 31,
    2007   2006   2005
     
Revenues from consolidated operations
                       
EPCO and affiliates
  $ 362,076     $ 98,671     $ 311  
Unconsolidated affiliates
    290,640       304,559       367,204  
     
Total
  $ 652,716     $ 403,230     $ 367,515  
         
 
                       
Operating costs and expenses
                       
EPCO and affiliates
  $ 329,699     $ 311,537     $ 293,134  
Unconsolidated affiliates
    32,765       31,606       23,563  
     
Total
  $ 362,464     $ 343,143     $ 316,697  
         
 
                       
General and administrative expenses
                       
EPCO and affiliates
  $ 56,518     $ 41,265     $ 40,954  
         
          We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties.
Relationship with EPCO and affiliates
          We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities that are not a part of our consolidated group of companies:
  §   EPCO and its private company subsidiaries;
 
  §   EPGP, our sole general partner;
 
  §   Enterprise GP Holdings, which owns and controls our general partner;
 
  §   TEPPCO, which is owned and controlled by Enterprise GP Holdings;
 
  §   the Employee Partnerships (see Note 5); and
 
  §   Energy Transfer Equity, an equity method investment of Enterprise GP Holdings.
          We also have an ongoing relationship with Duncan Energy Partners, the financial statements of which are consolidated with those of our own. Our transactions with Duncan Energy Partners are eliminated in consolidation. A description of our relationship with Duncan Energy Partners is presented within this Note 17.
          EPCO is a private company controlled by Dan L. Duncan, who is also a Director and Chairman of EPGP, our general partner. At December 31, 2007, EPCO and its affiliates beneficially owned 147,986,045 (or 34.0%) of our outstanding common units, which includes 13,454,498 of our common units owned by Enterprise GP Holdings. In addition, at December 31, 2007, EPCO and its affiliates beneficially owned 77.1% of the limited partner interests of Enterprise GP Holdings and 100% of its general partner, EPE Holdings. Enterprise GP Holdings owns all of the membership interests of EPGP. The principal business activity of EPGP is to act as our managing partner. The executive officers and certain of the directors of EPGP and EPE Holdings are employees of EPCO.
          As our general partner, EPGP received cash distributions of $124.4 million, $101.8 million and $76.8 million from us during the years ended December 31, 2007, 2006 and 2005, respectively. These amounts include incentive distributions of $107.4 million, $86.7 million and $63.9 million for the years ended December 31, 2007, 2006 and 2005, respectively.

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          We and EPGP are both separate legal entities apart from each other and apart from EPCO, Enterprise GP Holdings and their respective other affiliates, with assets and liabilities that are separate from those of EPCO, Enterprise GP Holdings and their respective other affiliates. EPCO and its private company subsidiaries and affiliates depend on the cash distributions they receive from us, Enterprise GP Holdings and other investments to fund their other operations and to meet their debt obligations. EPCO and its private company affiliates received $355.5 million, $306.5 million and $243.9 million in cash distributions from us and Enterprise GP Holdings during the years ended December 31, 2007, 2006 and 2005, respectively.
          The ownership interests in us that are owned or controlled by Enterprise GP Holdings are pledged as security under its credit facility. In addition, substantially all of the ownership interests in us that are owned or controlled by EPCO and its affiliates, other than those interests owned by Enterprise GP Holdings, Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under the credit facility of a private company affiliate of EPCO. This credit facility contains customary and other events of default relating to EPCO and certain affiliates, including Enterprise GP Holdings, TEPPCO and us.
          We have entered into an agreement with EPCO to provide trucking services to us for the transportation of NGLs and other products. For the years ended December 31, 2007, 2006 and 2005, we paid this trucking affiliate $17.5 million, $20.7 million and $17.6 million, respectively, for such services.
          We lease office space in various buildings from affiliates of EPCO. The rental rates in these lease agreements approximate market rates. For the years ended December 31, 2007, 2006 and 2005, we paid EPCO $5.6 million, $3.0 million and $2.7 million, respectively, for office space leases.
          Historically, we entered into transactions with a Canadian affiliate of EPCO for the purchase and sale of NGL products in the normal course of business. These transactions were at market-related prices. We acquired this affiliate in October 2006 and began consolidating its financial statements with those of our own from the date of acquisition. For the year ended December 31, 2005 our revenues from this former affiliate were $0.3 million and our purchases were $61.0 million. For the nine months ended September 30, 2006, our revenues from this former affiliate were $55.8 million and our purchases were $43.4 million.
     EPCO Administrative Services Agreement
          We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to an administrative services agreement (the “ASA”). We, Duncan Energy Partners, Enterprise GP Holdings, TEPPCO and our respective general partners are parties to the ASA. The significant terms of the ASA are as follows:
  §   EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services.
 
  §   We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided to us by EPCO.
 
  §   EPCO will allow us to participate as named insureds in its overall insurance program, with the associated premiums and other costs being allocated to us.
          Under the ASA, EPCO subleases to us (for $1 per year) certain equipment which it holds pursuant to operating leases and has assigned to us its purchase option under such leases (the “retained leases”).

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EPCO remains liable for the actual cash lease payments associated with these agreements. We record the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to partners’ equity accounted for as a general contribution to our partnership. At December 31, 2007, the retained leases were for a cogeneration unit and approximately 100 railcars. Should we decide to exercise the purchase options associated with the retained leases, $2.3 million would be payable in 2008 and $3.1 million in 2016.
          Our operating costs and expenses for the years ended December 31, 2007, 2006 and 2005 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. These reimbursements were $273.0 million, $285.4 million and $273.8 million during the years ended December 31, 2007, 2006 and 2005, respectively.
          Likewise, our general and administrative costs for the years ended December 31, 2007, 2006 and 2005 include amounts we reimburse to EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to ASA based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). These reimbursements were $56.5 million, $41.3 million and $41.0 million during the years ended December 31, 2007, 2006 and 2005, respectively.
          The ASA also addresses potential conflicts that may arise among Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), and the EPCO Group. The EPCO Group includes EPCO and its other affiliates, but excludes Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners and their respective general partners. With respect to potential conflicts, the ASA provides, among other things, that:
  §   If a business opportunity to acquire “equity securities” (as defined below) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), then Enterprise GP Holdings will have the first right to pursue such opportunity. The term “equity securities” is defined to include:
  §   general partner interests (or securities which have characteristics similar to general partner interests) or interests in “persons” that own or control such general partner or similar interests (collectively, “GP Interests”) and securities convertible, exercisable, exchangeable or otherwise representing ownership or control of such GP Interests; and
 
  §   incentive distribution rights and limited partner interests (or securities which have characteristics similar to incentive distribution rights or limited partner interests) in publicly traded partnerships or interests in “persons” that own or control such limited partner or similar interests (collectively, “non-GP Interests”); provided that such non-GP Interests are associated with GP Interests and are owned by the owners of GP Interests or their respective affiliates.
Enterprise GP Holdings will be presumed to want to acquire the equity securities until such time as EPE Holdings advises the EPCO Group, EPGP and DEP GP that it has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to equal or exceed $100 million, the decision to decline the acquisition will be made by the Chief Executive Officer of EPE Holdings after consultation with and subject to the approval of the ACG Committee of EPE Holdings. If the purchase price is reasonably likely to be less than $100 million, the Chief Executive Officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings.
In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, EPGP and DEP GP, Enterprise Products Partners will have the second right to pursue such

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      acquisition. Enterprise Products Partners will be presumed to want to acquire the equity securities until such time as EPGP advises the EPCO Group and DEP GP that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing EPGP’s Chief Executive Officer and ACG Committee.
 
      In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition.
 
      In the event Enterprise Products Partners abandons the acquisition opportunity for the equity securities and so notifies the EPCO Group and DEP GP, the EPCO Group may pursue the acquisition or offer the opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates, in either case, without any further obligation to any other party or offer such opportunity to other affiliates.
 
  §   If any business opportunity not covered by the preceding bullet point (i.e. not involving “equity securities”) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), or Duncan Energy Partners (including DEP GP), Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan Energy Partners. It will be presumed that Enterprise Products Partners will pursue the business opportunity until such time as its general partner advises the EPCO Group, EPE Holdings and DEP GP that it has abandoned the pursuit of such business opportunity.
 
      In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100 million, any decision to decline the business opportunity will be made by the Chief Executive Officer of EPGP after consultation with and subject to the approval of the ACG Committee of EPGP. If the purchase price or cost is reasonably likely to be less than $100 million, the Chief Executive Officer of EPGP may make the determination to decline the business opportunity without consulting EPGP’s ACG Committee.
 
      In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition.
 
      In the event that Enterprise Products Partners abandons the business opportunity for itself and Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the second right to pursue such business opportunity. It will be presumed that Enterprise GP Holdings will pursue such acquisition until such time as its general partner declines such opportunity (in accordance with the procedures described above for Enterprise Products Partners) and advises the EPCO Group that it has abandoned the pursuit of such business opportunity. Should this occur, the EPCO Group may either pursue the business opportunity or offer the business opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates.
          None of Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or their respective general partners or the EPCO Group have any obligation to present business opportunities to TEPPCO (including TEPPCO GP) or their controlled affiliates. Likewise, TEPPCO (including TEPPCO GP) and their controlled affiliates have no obligation to present business opportunities to Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or their respective general partners or the EPCO Group.

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     Relationship with TEPPCO
          TEPPCO became a related party to us in February 2005 in connection with the acquisition of TEPPCO GP by a private company subsidiary of EPCO. In May 2007, Enterprise GP Holdings purchased TEPPCO GP from this private company subsidiary of EPCO.
          We received $67.6 million, $42.9 million and a nominal amount from TEPPCO during the years ended December 31, 2007, 2006 and 2005, respectively, from the sale of hydrocarbon products. We paid TEPPCO $19.4 million, $24.0 million and $17.2 million for NGL pipeline transportation and storage services during the years ended December 31, 2007, 2006 and 2005, respectively.
          Purchase of Pioneer I plant from TEPPCO. In March 2006, we paid TEPPCO $38.2 million for its Pioneer I natural gas processing plant located in Opal, Wyoming and certain natural gas processing rights related to natural gas production from the Jonah and Pinedale fields located in the Greater Green River Basin in Wyoming. After an in-depth consideration of all relevant factors, this transaction was approved by the ACG Committee of our general partner and the Audit and Conflicts Committee of the general partner of TEPPCO. In addition, each party received a fairness opinion rendered by an independent advisor. TEPPCO will have no continued involvement in the contracts or in the operations of the Pioneer facility.
          Jonah Joint Venture with TEPPCO. In August 2006, we became a joint venture partner with TEPPCO in its Jonah Gas Gathering Company (“Jonah”), which owns the Jonah Gas Gathering System located in the Greater Green River Basin of southwestern Wyoming. The Jonah Gathering System gathers and transports natural gas produced from the Jonah and Pinedale fields to regional natural gas processing plants and major interstate pipelines that deliver natural gas to end-user markets.
          Prior to entering into the Jonah joint venture, we managed the construction of the Phase V expansion and funded the initial construction costs under a letter of intent we entered into in February 2006. In connection with the joint venture arrangement, we and TEPPCO plan to continue the Phase V expansion, which is expected to increase the capacity of the Jonah Gathering System from 1.5 Bcf/d to 2.4 Bcf/d and to significantly reduce system operating pressures, which we anticipate will lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which has increased the system gathering capacity to 2.0 Bcf/d, was completed in July 2007 and the final phase of this expansion is expected to be completed by April 2008. The total anticipated cost of the Phase V expansion is expected to be approximately $505.0 million. We continue to manage the Phase V construction project.
          Since August 1, 2006, we and TEPPCO have equally shared in the construction costs of the Phase V expansion. TEPPCO has reimbursed us $261.6 million, which represents 50% of total Phase V costs incurred through December 31, 2007. We had a receivable of $9.9 million from TEPPCO at December 31, 2007 for Phase V expansion costs.
          TEPPCO was entitled to all distributions from the joint venture until specified milestones were achieved, at which point, we became entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. Since the first phase of this expansion was reached in July 2007, we and TEPPCO have shared earnings based on a formula that takes into account our respective capital contributions, including expenditures by TEPPCO prior to the expansion.
          At December 31, 2007, we owned an approximate 19.4% interest in Jonah and TEPPCO owns 80.6%. We operate the Jonah system. We account for our investment in the Jonah joint venture using the equity method.
          The Jonah joint venture is governed by a management committee comprised of two representatives approved by us and two appointed by TEPPCO, each with equal voting power. After an in-depth consideration of all relevant factors, this transaction was approved by the ACG Committee of our general partner and the Audit and Conflicts Committee of the general partner of TEPPCO. The ACG Committee of our general partner received a fairness opinion in connection with this transaction. The

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transaction was reviewed and recommended for approval by the Audit and Conflicts Committee of TEPPCO GP with assistance from an independent financial advisor.
          We have agreed to indemnify TEPPCO from any and all losses, claims, demands, suits, liabilities, costs and expenses arising out of or related to breaches of our representations, warranties, or covenants related to the Jonah joint venture. A claim for indemnification cannot be filed until the losses suffered by TEPPCO exceed $1.0 million. The maximum potential amount of future payments under the indemnity agreement is limited to $100.0 million. All indemnity payments are net of insurance recoveries that TEPPCO may receive from third-party insurance carriers. We carry insurance coverage that may offset any payments required under the indemnification.
          Purchase of Houston-area pipelines from TEPPCO. In October 2006, we purchased certain idle pipeline assets in the Houston, Texas area from TEPPCO for $11.7 million in cash. The acquired pipelines became part of our Texas Intrastate System. The purchase of this asset was in accordance with the Board-approved management authorization policy.
          Purchase and lease of pipelines for DEP South Texas NGL Pipeline System from TEPPCO. In January 2007, we purchased a 10-mile segment of pipeline from TEPPCO located in the Houston area for $8.0 million. This pipeline segment is part of the DEP South Texas NGL Pipeline System that commenced operations in January 2007. In addition, we entered into a lease with TEPPCO for an 11-mile interconnecting pipeline located in the Houston area that is part of the DEP South Texas NGL Pipeline System. Although the primary term of the lease expired in September 2007, it is being renewed on a month-to-month basis until construction of a parallel pipeline is completed in early 2008. These transactions were in accordance with the Board-approved management authorization policy.
Relationship with Energy Transfer Equity
          Enterprise GP Holdings acquired equity method investments in Energy Transfer Equity and its general partner in May 2007. As a result, Energy Transfer Equity and its consolidated subsidiaries became related parties to our consolidated businesses.
          For the eight months ended December 31, 2007, we recorded $294.4 million of revenues from Energy Transfer Partners, L.P. (“ETP”), primarily from NGL marketing activities. We incurred $35.2 million in operating costs and expenses for the eight months ended December 31, 2007. We have a long-term revenue generating contract with Titan Energy Partners, L.P. (“Titan”), a consolidated subsidiary of ETP. Titan purchases substantially all of its propane requirements from us. The contract continues until March 31, 2010 and contains renewal and extension options. We and Energy Transfer Company (“ETC OLP”) transport natural gas on each other’s systems and share operating expenses on certain pipelines. ETC OLP also sells natural gas to us.
Relationships with Unconsolidated Affiliates
          Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. See Note 16 of the Notes to Consolidated Financial Statements for a discussion of this alignment of commercial interests. Since we and our affiliates hold ownership interests in these entities and directly or indirectly benefit from our related party transactions with such entities, they are presented here.
          The following information summarizes significant related party transactions with our current unconsolidated affiliates:
  §   We sell natural gas to Evangeline, which, in turn, uses the natural gas to satisfy supply commitments it has with a major Louisiana utility. Revenues from Evangeline were $268.0 million, $277.7 million and $331.5 million for the years ended December 31, 2007, 2006 and 2005. In addition, we furnished $1.1 million in letters of credit on behalf of Evangeline at December 31, 2007.

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  §   We pay Promix for the transportation, storage and fractionation of NGLs. In addition, we sell natural gas to Promix for its plant fuel requirements. Expenses with Promix were $30.4 million, $34.9 million and $26.0 million for the years ended December 31, 2007, 2006 and 2005. Revenues from Promix were $17.3 million, $21.8 million and $25.8 million for the years ended December 31, 2007, 2006 and 2005.
 
  §   We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $9.3 million, $8.9 million and $8.3 million for the years ended December 31, 2007, 2006 and 2005.
Relationship with Duncan Energy Partners
          In September 2006, we formed a consolidated subsidiary, Duncan Energy Partners, to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO. On February 5, 2007, this subsidiary completed its initial public offering of 14,950,000 common units at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of $291.9 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of these net proceeds to Enterprise Products Partners (along with $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units of Duncan Energy Partners). Duncan Energy Partners used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units it had originally issued to Enterprise Products Partners, resulting in the final amount of 5,351,571 common units beneficially owned by Enterprise Products Partners. We used the cash received from Duncan Energy Partners to temporarily reduce amounts outstanding under EPO’s Multi-Year Revolving Credit Facility.
          In addition to the 34% direct ownership interest we retained in certain subsidiaries of Duncan Energy Partners, we also own the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units. EPO directs the business operations of Duncan Energy Partners through its control of Duncan Holdings, LLC (“DEP GP”). Certain of our officers and directors are also beneficial owners of common units of Duncan Energy Partners (see Item 12).
          For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments. All intercompany transactions between us and Duncan Energy Partners are eliminated in the preparation of our consolidated financial statements. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the subsidiaries contributed to Duncan Energy Partners. Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of minority interest in our consolidated financial statements.
          The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, we do not have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.
          We have significant involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions: (i) we utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses; (ii) we buy natural gas from and sell natural gas to Acadian Gas in connection with our normal business activities; and (iii) we are the sole shipper on the DEP South Texas NGL Pipeline System.
          We may contribute other equity interests in our subsidiaries to Duncan Energy Partners in the near term and use the proceeds we receive from Duncan Energy Partners to fund our capital spending program.
          For additional information regarding Duncan Energy Partners, see “Other Items — Initial Public Offering of Duncan Energy Partners” under Item 7 of this annual report.

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          Omnibus Agreement. On February 5, 2007, EPO and Duncan Energy Partners entered into an Omnibus Agreement that governs our relationship with Duncan Energy Partners on the following matters:
  §   indemnification for certain environmental liabilities, tax liabilities and right-of-way defects;
 
  §   reimbursement of certain expenditures incurred by DEP South Texas NGL and Mont Belvieu Caverns;
 
  §   a right of first refusal to EPO in Duncan Energy Partners’ current and future subsidiaries and a right of first refusal on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business; and
 
  §   a preemptive right with respect to equity securities issued by certain of Duncan Energy Partners’ subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.
          EPO has indemnified Duncan Energy Partners against certain pre-February 2007 environmental and related liabilities associated with the assets EPO contributed to Duncan Energy Partners at the time of its initial public offering. These liabilities include both known and unknown environmental and related liabilities. This indemnification obligation will terminate on February 5, 2010. There is an aggregate cap of $15.0 million on the amount of indemnity coverage. In addition, Duncan Energy Partners is not entitled to indemnification until the aggregate amount of claims it incurs exceeds $250 thousand. Liabilities resulting from a change of law after February 5, 2007 are excluded from the EPO environmental indemnity. In addition, EPO has indemnified Duncan Energy Partners for liabilities related to:
  §   certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to Duncan Energy Partners in connection with its initial public offering are located and failure to obtain certain consents and permits necessary to conduct its business that arise through February 5, 2010; and
 
  §   certain income tax liabilities attributable to the operation of the assets contributed to Duncan Energy Partners in connection with its initial public offering prior to February 5, 2007.
          The Omnibus Agreement may not be amended without the prior approval of the ACG Committee if the proposed amendment will, in the reasonable discretion of DEP GP, adversely affect holders of the it’s common units.
          Neither we, nor EPO and any of its affiliates are restricted under the Omnibus Agreement from competing with Duncan Energy Partners. Except as otherwise expressly agreed in the EPCO administrative services agreement, EPO and any of its affiliates may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer Duncan Energy Partners the opportunity to purchase or construct those assets. These agreements are in addition to other agreements relating to business opportunities and potential conflicts of interest set forth in the administrative services agreement with EPO, EPCO and other affiliates of EPCO.
           In certain cases, EPO is responsible for funding 100% of project costs rather than sharing such costs with Duncan Energy Partners in accordance with the existing sharing ratio of 66% funded by Duncan Energy Partners and 34% funded by EPO. Under the Omnibus Agreement, EPO agreed to make additional contributions to Duncan Energy Partners as reimbursement for Duncan Energy Partners’ 66% share of any excess project costs above (i) the $28.6 million of estimated project costs to complete the Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated project costs for additional Mont Belvieu brine production capacity and above-ground storage reservoir projects. These projects were in progress at the time of Duncan Energy Partners’ initial public offering. In December 2007, EPO made cash contributions totaling $9.9 million to Duncan Energy Partners’ subsidiaries in connection with the Omnibus Agreement.
           In December 2007, EPO made an additional $38.1 million cash contribution to Mont Belvieu Caverns for capital expenditures in which Duncan Energy Partners is not a participant. This contribution was in accordance with provisions of the Mont Belvieu Caverns’ limited liability company agreement, which states that when Duncan Energy Partners elects to not participate in certain projects, then EPO is responsible for funding 100% of such projects. To the extent such non-participated projects generate incremental earnings for Mont Belvieu Caverns in the future, the sharing ratio for Mont Belvieu Caverns will be adjusted to allocate such incremental cash flows to EPO. Under the terms of the agreement, Duncan Energy Partners may elect to reacquire for consideration a 66% share of these projects at a later date.

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Note 18. Provision for Income Taxes
          Our provision for income taxes relates primarily to federal and state income taxes of Seminole and Dixie, our two largest corporations subject to such income taxes. In addition, with the amendment of the Texas Franchise Tax in 2006, we have become a taxable entity in the state of Texas. Our federal and state income tax provision is summarized below:
                         
    For the Year Ended December 31,
    2007   2006   2005
     
Current:
                       
Federal
  $ 4,828     $ 7,694     $ 1,105  
State
    3,871       1,148       301  
     
Total current
    8,699       8,842       1,406  
         
Deferred:
                       
Federal
    2,784       6,109       5,968  
State
    3,774       6,372       988  
     
Total deferred
    6,558       12,481       6,956  
         
Total provision for income taxes
  $ 15,257     $ 21,323     $ 8,362  
         
          A reconciliation of the provision for income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows:
                         
    For the Year Ended December 31,
    2007   2006   2005
     
Pre Tax Net Book Income (“NBI”)
  $ 579,574     $ 630,085     $ 437,838  
 
                       
 
                       
Revised Texas franchise tax
    7,146       8,119        
State income taxes (net of federal benefit)
    325       (396 )     838  
Federal income taxes computed by applying the federal statutory rate to NBI of corporate entities
    5,318       13,347       7,656  
Taxes charged to cumulative effect of changes in accounting principle
          (3 )     65  
Valuation allowance
    2,347       123        
Other permanent differences
    121       133       (197 )
     
Provision for income taxes
    15,257     $ 21,323     $ 8,362  
         
Effective income tax rate
    2.6 %     3.4 %     1.9 %
         

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          Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2007 and 2006 are as follows:
                 
    At December 31,  
    2007     2006  
Deferred Tax Assets:
               
Net operating loss carryovers
  $ 23,270     $ 19,175  
Credit carryover
    26       26  
Charitable contribution carryover
    16       12  
Employee benefit plans
    3,214       1,990  
Deferred revenue
    642       328  
Reserve for legal fees and damages
    478        
Equity investment in partnerships
    409       223  
Asset retirement obligation
    80       43  
     
Accruals
    1,068       709  
     
Total Deferred Tax Assets
    29,203       22,506  
     
Valuation allowance
    (5,345 )     (2,994 )
     
Net Deferred Tax Assets
    23,858       19,512  
     
Deferred Tax Liabilities:
               
Property, plant and equipment
    40,520       30,604  
Other
    99       78  
     
Total Deferred Tax Liabilities
    40,619       30,682  
     
Total Net Deferred Tax Liabilities
  $ (16,761 )   $ (11,170 )
     
 
               
Current portion of total net deferred tax assets
  $ 1,081     $ 698  
       
Long-term portion of total net deferred tax liabilities
  $ (17,842 )   $ (11,868 )
       
          We had net operating loss carryovers of $23.3 million and $19.2 million at December 31, 2007 and 2006, respectively. These losses expire in various years between 2008 and 2028 and are subject to limitations on their utilization. We record a valuation allowance to reduce our deferred tax assets to the amount of future tax benefit that is more likely than not to be realized. The valuation allowance was $5.3 million and $3.0 million at December 31, 2007 and 2006, respectively, and serves to reduce the recognized tax benefit associated with carryovers of our corporate entities to an amount that will, more likely than not, be realized.  The $2.3 million increase in valuation allowance for 2007 is comprised primarily of $1.6 million for Canadian Enterprise Gas Products, Ltd.
          On May 18, 2006, the State of Texas enacted House Bill 3 which revised the pre-existing state franchise tax. In general, legal entities that conduct business in Texas are subject to the Revised Texas Franchise Tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits.
          Although the bill states that the Revised Texas Franchise Tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Due to the enactment of the Revised Texas Franchise Tax, we recorded a net deferred tax liability of $3.8 million and $6.6 million during the years ended December 31, 2007 and 2006, respectively. The offsetting net charge of $3.8 million and $6.6 million is shown on our Statement of Consolidated Operations for the years ended December 31, 2007 and 2006, respectively, as a component of provision for income taxes.

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Note 19. Earnings Per Unit
          Basic earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the weighted-average number of distribution-bearing units outstanding during a period. Diluted earnings per unit is computed by dividing net income or loss allocated to limited partner interests by the sum of (i) the weighted-average number of distribution-bearing units outstanding during a period (as used in determining basic earnings per unit); (ii) the weighted-average number of performance-based phantom units outstanding during a period; and (iii) the number of incremental common units resulting from the assumed exercise of dilutive unit options outstanding during a period (the “incremental option units”).
          In a period of net losses, restricted units, phantom units and incremental option units are excluded from the calculation of diluted earnings per unit due to their antidilutive effect. The dilutive incremental option units are calculated using the treasury stock method, which assumes that proceeds from the exercise of all in-the-money options at the end of each period are used to repurchase common units at an average market value during the period. The amount of common units remaining after the proceeds are exhausted represents the potentially dilutive effect of the securities.
          The amount of net income or loss allocated to limited partner interests is net of our general partner’s share of such earnings. The following table presents the allocation of net income to EPGP for the periods indicated:
                         
    For The Year Ended December 31,
    2007   2006   2005
     
Net income
  $ 533,674     $ 601,155     $ 419,508  
Less incentive earnings allocations to EPGP
    (107,421 )     (86,710 )     (63,884 )
     
Net income available after incentive earnings allocation
    426,253       514,445       355,624  
Multiplied by EPGP ownership interest
    2.0 %     2.0 %     2.0 %
     
Standard earnings allocation to EPGP
  $ 8,525     $ 10,289     $ 7,112  
         
 
                       
Incentive earnings allocation to EPGP
  $ 107,421     $ 86,710     $ 63,884  
Standard earnings allocation to EPGP
    8,525       10,289       7,112  
     
EPGP interest in net income
  $ 115,946     $ 96,999     $ 70,996  
         

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          The following table presents our calculation of basic and diluted earnings per unit for the periods indicated:
                         
    For The Year Ended December 31,  
    2007   2006   2005  
Income before change in accounting principle and EPGP interest
  $ 533,674     $ 599,683     $ 423,716  
Cumulative effect of change in accounting principle
          1,472       (4,208 )
         
Net income
    533,674       601,155       419,508  
EPGP interest in net income
    (115,946 )     (96,999 )     (70,996 )
     
Net income available to limited partners
  $ 417,728     $ 504,156     $ 348,512  
         
BASIC EARNINGS PER UNIT
                       
Numerator
                       
Income before change in accounting principle and EPGP interest
  $ 533,674     $ 599,683     $ 423,716  
Cumulative effect of change in accounting principle
          1,472       (4,208 )
EPGP interest in net income
    (115,946 )     (96,999 )     (70,996 )
         
Limited partners’ interest in net income
  $ 417,728     $ 504,156     $ 348,512  
         
Denominator
                       
Common units
    432,513       413,472       413,472  
Time-vested restricted units
    1,446       970       970  
     
Total
    433,959       414,442       414,442  
         
Basic earnings per unit
                       
Income per unit before change in accounting principle and EPGP interest
  $ 1.23     $ 1.45     $ 1.11  
Cumulative effect of change in accounting principle
                (0.01 )
EPGP interest in net income
    (0.27 )     (0.23 )     (0.19 )
     
Limited partners’ interest in net income
  $ 0.96     $ 1.22     $ 0.91  
         
DILUTED EARNINGS PER UNIT
                       
Numerator
                       
Income before change in accounting principle and EPGP interest
  $ 533,674     $ 599,683     $ 423,716  
Cumulative effect of change in accounting principle
          1,472       (4,208 )
EPGP interest in net income
    (115,946 )     (96,999 )     (70,996 )
         
Limited partners’ interest in net income
  $ 417,728     $ 504,156     $ 348,512  
         
Denominator
                       
Common units
    432,513       413,472       381,857  
Time-vested restricted units
    1,446       970       606  
Performance-based restricted units
    9       20       45  
Incremental option units
    459       297       455  
     
Total
    434,427       414,759       382,963  
         
Diluted earnings per unit
                       
Income per unit before change in accounting principle and EPGP interest
  $ 1.23     $ 1.45     $ 1.11  
Cumulative effect of change in accounting principle
                (0.01 )
EPGP interest in net income
    (0.27 )     (0.23 )     (0.19 )
         
Limited partners’ interest in net income
  $ 0.96     $ 1.22     $ 0.91  
         
Note 20. Commitments and Contingencies
Litigation
          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

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litigation, pending or threatened, that could have a significant adverse effect on our financial position, cash flows or results of operations.
          On September 18, 2006, Peter Brinckerhoff, a purported unitholder of TEPPCO, filed a complaint in the Court of Chancery of New Castle County in the State of Delaware, in his individual capacity, as a putative class action on behalf of other unitholders of TEPPCO, and derivatively on behalf of TEPPCO, concerning, among other things, certain transactions involving TEPPCO and us or our affiliates.  Mr. Brinkerhoff filed an amended complaint on July 12, 2007. The amended complaint names as defendants (i) TEPPCO, its current and certain former directors, and certain of its affiliates; (ii) us and certain of our affiliates; (iii) EPCO, Inc.; and (iv) Dan L. Duncan. 
          The amended complaint alleges, among other things, that the defendants have caused TEPPCO to enter into certain transactions with us or our affiliates that were unfair to TEPPCO or otherwise unfairly favored us or our affiliates over TEPPCO.  These transactions are alleged to include the joint venture to further expand the Jonah Gathering System entered into by TEPPCO and one of our affiliates in August 2006 and the sale by TEPPCO to one of our affiliates of the Pioneer gas processing plant in March 2006. The amended complaint seeks (i) rescission of these transactions or an award of rescissory damages with respect thereto; (ii) damages for profits and special benefits allegedly obtained by defendants as a result of the alleged wrongdoings in the amended complaint; and (iii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. We believe this lawsuit is without merit and intend to vigorously defend against it. See Note 17 for additional information regarding our relationship with TEPPCO.
          On February 13, 2007, EPO received notice from the U.S. Department of Justice (“DOJ”) that it was the subject of a criminal investigation related to an ammonia release in Kingman County, Kansas on October 27, 2004 from a pressurized anhydrous ammonia pipeline owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”). EPO is the operator of this pipeline. On February 14, 2007, EPO received a letter from the Environment and Natural Resources Division (“ENRD”) of the DOJ regarding this incident and a previous release of ammonia on September 27, 2004 from the same pipeline.  The ENRD has indicated that it may pursue civil damages against EPO and Magellan as a result of these incidents.  Based on this correspondence from the ENRD, the statutory maximum amount of civil fines that could be assessed against EPO and Magellan is up to $17.4 million in the aggregate. EPO is cooperating with the DOJ and is hopeful that an expeditious resolution of this civil matter acceptable to all parties will be reached in the near future.  Magellan has agreed to indemnify EPO for the civil matter. On September 4, 2007, we and the DOJ entered into a plea agreement whereby a wholly-owned subsidiary of EPO, Mapletree, LLC, pleaded guilty to a misdemeanor charge of negligence in connection with the releases and paid a fine of $1.0 million. The plea agreement concludes the DOJ’s criminal investigation into the ammonia releases. At this time, we do not believe that a final resolution of the civil claims by the ENRD will have a material impact on our consolidated financial position, cash flows or results of operations.
          On October 25, 2006, a rupture in the Magellan Ammonia Pipeline resulted in the release of ammonia near Clay Center, Kansas. The pipeline has been repaired and environmental remediation tasks related to this incident have been completed. At this time, we do not believe that this incident will have a material impact on our consolidated financial position, cash flows or results of operations.
          Several lawsuits have been filed by municipalities and other water suppliers against a number of manufacturers of reformulated gasoline containing methyl tertiary butyl ether. In general, such suits have not named manufacturers of this product as defendants, and there have been no such lawsuits filed against our subsidiary that owns an octane-additive production facility. It is possible, however, that former manufacturers such as our subsidiary could ultimately be added as defendants in such lawsuits or in new lawsuits.

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     Contractual Obligations
          The following table summarizes our various contractual obligations at December 31, 2007. A description of each type of contractual obligation follows:
                                                         
    Payment or Settlement due by Period
Contractual Obligations   Total   2008   2009   2010   2011   2012   Thereafter
 
Scheduled maturities of long-term debt
  $ 6,896,500     $     $ 500,000     $ 591,840     $ 650,000     $ 697,160     $ 4,457,500  
Operating lease obligations
  $ 325,705     $ 27,785     $ 25,866     $ 23,306     $ 23,785     $ 23,137     $ 201,826  
Purchase obligations:
                                                       
Product purchase commitments:
                                                       
Estimated payment obligations:
                                                       
Natural gas
  $ 685,600     $ 137,345     $ 136,970     $ 136,970     $ 136,970     $ 137,345     $  
NGLs
  $ 4,041,275     $ 697,277     $ 415,132     $ 415,132     $ 415,132     $ 415,132     $ 1,683,470  
Petrochemicals
  $ 4,065,675     $ 1,751,152     $ 746,916     $ 514,155     $ 233,745     $ 141,623     $ 678,084  
Other
  $ 60,385     $ 31,392     $ 14,962     $ 2,152     $ 2,051     $ 1,780     $ 8,048  
Underlying major volume commitments:
                                                       
Natural gas (in BBtus)
    91,350       18,300       18,250       18,250       18,250       18,300        
NGLs (in MBbls)
    50,798       9,745       5,086       5,086       5,086       5,086       20,709  
Petrochemicals (in MBbls)
    45,207       20,115       8,100       5,604       2,541       1,556       7,291  
Service payment commitments
  $ 8,962     $ 6,745     $ 1,564     $ 93     $ 93     $ 93     $ 374  
Capital expenditure commitments
  $ 569,654     $ 569,654     $     $     $     $     $  
          Scheduled Maturities of Long-Term Debt. We have long-term and short-term payment obligations under debt agreements such as the indentures governing EPO’s senior notes and the credit agreement governing EPO’s Multi-Year Revolving Credit Facility. Amounts shown in the preceding table represent our scheduled future maturities of debt principal for the periods indicated. See Note 14 for additional information regarding our consolidated debt obligations.
          Operating Lease Obligations. We lease certain property, plant and equipment under noncancelable and cancelable operating leases. Amounts shown in the preceding table represent minimum cash lease payment obligations under our operating leases with terms in excess of one year.
          Our significant lease agreements involve (i) the lease of underground caverns for the storage of natural gas and NGLs, (ii) leased office space with an affiliate of EPCO, (iii) a railcar unloading terminal in Mont Belvieu, Texas and (iv) land held pursuant to right-of-way agreements. In general, our material lease agreements have original terms that range from 2 to 28 years and include renewal options that could extend the agreements for up to an additional 20 years.
          Lease expense is charged to operating costs and expenses on a straight line basis over the period of expected economic benefit. Contingent rental payments are expensed as incurred. We are generally required to perform routine maintenance on the underlying leased assets. In addition, certain leases give us the option to make leasehold improvements. Maintenance and repairs of leased assets resulting from our operations are charged to expense as incurred. We did not make any significant leasehold improvements during the years ended December 31, 2007, 2006 or 2005; however, we did incur $9.3 million of repair costs associated with our lease of an underground natural gas storage facility in 2006.
          The operating lease commitments shown in the preceding table exclude the non-cash, related party expense associated with equipment leases contributed to us by EPCO at our formation (the “retained leases”). EPCO remains liable for the actual cash lease payments associated with these agreements, which it accounts for as operating leases. At December 31, 2007, the retained leases were for a cogeneration unit and approximately 100 railcars. EPCO’s minimum future rental payments under these leases are $2.1 million for 2008, $0.7 million for each of the years 2009 through 2015 and $0.3 million for 2016. We record the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to partners’ equity accounted for as a general contribution to our partnership.
          The retained lease agreements contain lessee purchase options, which are at prices that approximate fair value of the underlying leased assets. EPCO has assigned these purchase options to us.

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Should we decide to exercise the remaining purchase options, up to an additional $2.3 million would be payable in 2008 and $3.1 million in 2016.
          Lease and rental expense included in operating costs and expenses was $38.5 million, $39.3 million and $34.9 million during the years ended December 31, 2007, 2006 and 2005, respectively.
          Purchase Obligations. We define a purchase obligation as an agreement to purchase goods or services that is enforceable and legally binding (unconditional) on us that specifies all significant terms, including: fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transactions. We have classified our unconditional purchase obligations into the following categories:
  §   We have long and short-term product purchase obligations for NGLs, certain petrochemicals and natural gas with third-party suppliers. The prices that we are obligated to pay under these contracts approximate market prices at the time we take delivery of the volumes. The preceding table shows our volume commitments and estimated payment obligations under these contracts for the periods indicated. Our estimated future payment obligations are based on the contractual price under each contract for purchases made at December 31, 2007 applied to all future volume commitments. Actual future payment obligations may vary depending on market prices at the time of delivery. At December 31, 2007, we do not have any product purchase commitments with fixed or minimum pricing provisions with remaining terms in excess of one year.
 
  §   We have long and short-term commitments to pay third-party providers for services such as equipment maintenance agreements. Our contractual payment obligations vary by contract. The preceding table shows our future payment obligations under these service contracts.
 
  §   We have short-term payment obligations relating to our capital projects and those of our unconsolidated affiliates. These commitments represent unconditional payment obligations to vendors for services rendered or products purchased. The preceding table presents our share of such commitments for the periods indicated.
     Commitments under equity compensation plans of EPCO
          In accordance with our agreements with EPCO, we reimburse EPCO for our share of its compensation expense associated with certain employees who perform management, administrative and operating functions for us (see Note 17). This includes costs associated with unit option awards granted to these employees to purchase our common units. At December 31, 2007, there were 2,315,000 unit options outstanding for which we were responsible for reimbursing EPCO for the costs of such awards.
          The weighted-average strike price of unit option awards outstanding at December 31, 2007 was $26.18 per common unit. At December 31, 2007, 335,000 of these unit options were exercisable. An additional 285,000, 380,000, 510,000 and 805,000 of these unit options will be exercisable in 2008, 2009, 2010 and 2011, respectively. As these options are exercised, we will reimburse EPCO in the form of a special cash distribution for the difference between the strike price paid by the employee and the actual purchase price paid for the units awarded to the employee. See Note 5 for additional information regarding our accounting for equity awards.
     Performance Guaranty
          In December 2004, a subsidiary of ours entered into the Independence Hub Agreement (the “Agreement”) with six oil and natural gas producers. The Agreement, as amended, obligated our subsidiary to construct the Independence Hub offshore platform and to process 1 Bcf/d of natural gas and condensate for the producers. We guaranteed to the producers the construction-related performance of our subsidiary up to an amount of $340.8 million. The performance guaranty expired during the second quarter of 2007. However at December 31, 2006, as a component of other current liabilities on our Consolidated Balance Sheet, we recorded the fair value of the performance guaranty at an estimated $1.2 million using

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an expected present value approach. This was in accordance with FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,”
     Other Claims
          As part of our normal business activities with joint venture partners and certain customers and suppliers, we occasionally have claims made against us as a result of disputes related to contractual agreements or similar arrangements. As of December 31, 2007, claims against us totaled approximately $37.9 million. These matters are in various stages of assessment and the ultimate outcome of such disputes cannot be reasonably estimated. However, in our opinion, the likelihood of a material adverse outcome related to disputes against us is remote. Accordingly, accruals for loss contingencies related to these matters, if any, that might result from the resolution of such disputes have not been reflected in our consolidated financial statements.
     Other Commitments
           We transport and store natural gas, NGLs and petrochemicals for third parties under various processing, storage, transportation and similar agreements. These volumes are (i) accrued as product payables on our Consolidated Balance Sheets, (i) in transit for delivery to our customers or (iii) held at our storage facilities for redelivery to our customers. We are insured against any physical loss of such volumes due to catastrophic events. Under the terms of our natural gas, NGL and petrochemical storage agreements, we are generally required to redeliver volumes to the owner on demand. At December 31, 2007, NGL and petrochemical products aggregating 25.2 million barrels were due to be redelivered to their owners along with 16,223 BBtus of natural gas. See Note 2 for more information regarding accrued product payables.
Note 21. Significant Risks and Uncertainties
     Nature of Operations in Midstream Energy Industry
          Our operations are within the midstream energy industry, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, certain petrochemicals and crude oil. As such, our results of operations, cash flows and financial condition may be affected by changes in the commodity prices of these hydrocarbon products, including changes in the relative price levels among these products. In general, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control.
          Our profitability could be impacted by a decline in the volume of hydrocarbon products transported, gathered or processed at our facilities. A material decrease in natural gas or crude oil production or crude oil refining for reasons such as depressed commodity prices or a decrease in exploration and development activities, could result in a decline in the volume of natural gas, NGLs and crude oil handled by our facilities.
          A reduction in demand for NGL products by the petrochemical, refining or heating industries, whether because of (i) general economic conditions, (ii) reduced demand by consumers for the end products made using NGLs, (iii) increased competition from petroleum-based products due to pricing differences, (iv) adverse weather conditions, (v) government regulations affecting energy commodity prices, production levels of hydrocarbons or the content of motor gasoline or (vi) other reasons, could adversely affect our results of operations, cash flows and financial position.
     Credit Risk due to Industry Concentrations
          A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL and petrochemical industries. This concentration could affect our overall exposure to credit risk since these customers may be affected by similar economic or other conditions. We generally do not require collateral for our accounts receivable; however, we do attempt to negotiate offset, prepayment, or automatic

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debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults.
          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.
     Counterparty Risk with respect to Financial Instruments
          Where we are exposed to credit risk in our financial instrument transactions, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit and/or margin limits and monitor the appropriateness of these limits on an ongoing basis. We generally do not require collateral for our financial instrument transactions.
     Weather-Related Risks
          We participate as named insureds in EPCO’s current insurance program, which provides us with property damage, business interruption and other coverages, which are customary for the nature and scope of our operations. EPCO attempts to place all insurance coverage with carriers having ratings of “A” or higher. However, two carriers associated with the EPCO insurance program were downgraded by Standard & Poor’s during 2006. One of these carriers is currently at “A-” and the other, “BBB.” At present, there is no indication that these two carriers would be unable to fulfill any insuring obligation. Furthermore, we currently do not have any claims which might be affected by these carriers. EPCO continues to monitor these situations.
          We believe EPCO maintains adequate insurance coverage on our behalf; however, insurance will not cover every type of interruption that might occur. As a result of severe hurricanes such as Katrina and Rita that occurred in 2005, market conditions for obtaining property damage insurance coverage were difficult during 2006. Under EPCO’s renewed insurance programs, coverage was more restrictive, including increased physical damage and business interruption deductibles. For example, our deductible for onshore physical damage increased from $2.5 million to $5.0 million per event and our deductible period for onshore business interruption claims increased from 30 days to 60 days. Additional restrictions will be applied in connection with damage caused by named windstorms.
          In addition to changes in coverage, the cost of property damage insurance increased substantially between 2006 and prior periods. At present, our annualized cost of insurance premiums for all lines of coverage is approximately $52.4 million. During the year ended December 31, 2006, our annualized cost of insurance premiums for all lines of coverage was approximately $49.2 million, which represented a $28.1 million, or 133%, increase from our 2005 annualized insurance cost.
          If we were to incur a significant liability for which we were not fully insured, it could have a material impact on our consolidated 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 to reimburse us for repair costs or lost income. Any event that interrupts the revenues generated by our consolidated operations, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to pay distributions to partners and, accordingly, adversely affect the market price of our common units.
          The following is a discussion of the general status of our insurance claims related to recent significant storm events. To the extent we include any estimate or range of estimates regarding the dollar value of damages, please be aware that a change in our estimates may occur as additional information becomes available.
          Hurricane Ivan insurance claims. During the years ended December 31, 2007 and 2006, we received cash reimbursements from insurance carriers totaling $1.3 million and $24.1 million, respectively,

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related to property damage claims. If the final recovery of funds is different than the amount previously expended, we will recognize an income impact at that time.
          We have submitted business interruption insurance claims for our estimated losses caused by Hurricane Ivan, which struck the eastern U.S. Gulf Coast region in September 2004. During the years ended December 31, 2007 and 2006, we received $0.4 million and $17.4 million of nonrefundable cash proceeds from such claims. We are continuing our efforts to collect residual balances and expect to complete the process during 2008. To the extent we receive nonrefundable cash proceeds from business interruption insurance claims, they are recorded as a gain in our Statements of Consolidated Operations in the period of receipt.
          Hurricanes Katrina and Rita insurance claims. Hurricanes Katrina and Rita, both significant storms, affected certain of our Gulf Coast assets in August and September of 2005, respectively. With respect to these storms, we have $37.6 million of estimated property damage claims outstanding at December 31, 2007, that we believe are probable of collection during the period 2008 through 2009. We continue to pursue collection of our property damage claims related to these named storms. As of December 31, 2007, we had received practically all proceeds from our business interruption claims related to these storm events.
          The following table summarizes proceeds we received during the periods indicated from business interruption and property damage insurance claims with respect to certain named storms:
                 
    For the Year Ended December 31,
    2007   2006
Business interruption proceeds:
               
Hurricane Ivan
  $ 377     $ 17,382  
Hurricane Katrina
    19,005       24,500  
Hurricane Rita
    14,955       22,000  
Other
    996        
     
Total proceeds
    35,333       63,882  
     
Property damage proceeds:
               
Hurricane Ivan
    1,273       24,104  
Hurricane Katrina
    79,651       7,500  
Hurricane Rita
    24,105       3,000  
Other
    184        
     
Total proceeds
    105,213       34,604  
     
Total
  $ 140,546     $ 98,486  
     
          During 2007, we collected $0.8 million of business interruption proceeds that were not related to storm events. As well, during 2005, we received $4.8 million of nonrefundable cash proceeds from business interruption claims.

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Note 22. Supplemental Cash Flow Information
          The following table provides information regarding (i) the net effect of changes in our operating assets and liabilities; (ii) cash payments for interest and (iii) cash payments for federal and state income taxes for the periods indicated.
                         
    For the Year Ended December 31,
    2007   2006   2005
     
Decrease (increase) in:
                       
Accounts and notes receivable
  $ (703,346 )   $ 155,628     $ (363,857 )
Inventories
    (14,051 )     (66,288 )     (148,846 )
Prepaid and other current assets
    41,266       14,261       (51,163 )
Other assets
    5,630       (22,581 )     58,762  
Increase (decrease) in:
                       
Accounts payable
    53,981       (12,278 )     45,802  
Accrued product payables
    862,941       (8,344 )     349,979  
Accrued expenses
    120,054       (62,963 )     (161,989 )
Accrued interest
    40,107       19,671       858  
Other current liabilities
    37,248       74,206       2,274  
Other liabilities
    (2,524 )     (7,894 )     1,785  
     
Net effect of changes in operating accounts
  $ 441,306     $ 83,418     $ (266,395 )
     
 
                       
Cash payments for interest, net of $75,476, $55,660 and $22,046 capitalized in 2007, 2006 and 2005, respectively
  $ 325,339     $ 213,365     $ 239,088  
     
 
                       
Cash payments for federal and state income taxes
  $ 5,760     $ 10,497     $ 5,160  
     
          The following table provides supplemental cash flow information regarding business combinations we completed during the periods indicated. See Note 12, for additional information regarding our business combination transactions.
                         
    For the Year Ended December 31,
    2007   2006   2005
     
Assets acquired
  $ 37,037     $ 477,015     $ 353,176  
Less liabilities assumed
    (1,244 )     (19,403 )     (23,940 )
     
Net assets acquired
    35,793       457,612       329,236  
Less equity issued
          (181,112 )      
Less cash acquired
                (2,634 )
     
Cash used for business combinations, net of cash received
  $ 35,793     $ 276,500     $ 326,602  
     
          We incurred liabilities for construction in progress that had not been paid at December 31, 2007, 2006 and 2005 of $95.5 million, $195.1 million and $130.2 million, respectively. Such amounts are not included under the caption “Capital expenditures” on the Statements of Consolidated Cash Flows.
          Third parties may be obligated to reimburse us for all or a portion of expenditures on certain of our capital projects. The majority of such arrangements are associated with projects related to pipeline construction and production well tie-ins. We received $57.5 million, $60.5 million and $47.0 million as contributions in aid of our construction costs during the years ended December 31, 2007, 2006 and 2005, respectively.
          In June 2005, we received $47.5 million in cash from Cameron Highway as a return of investment. These funds were distributed to us in connection with the refinancing of Cameron Highway’s project debt.

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Note 23. Quarterly Financial Information (Unaudited)
          The following table presents selected quarterly financial data for the years ended December 31, 2007 and 2006:
                                 
    First   Second   Third   Fourth
    Quarter   Quarter   Quarter   Quarter
     
For the Year Ended December 31, 2007:
                               
Revenues
  $ 3,322,854     $ 4,212,806     $ 4,111,996     $ 5,302,469  
Operating income
    187,924       214,562       210,830       269,721  
Income before change in accounting principle
    112,045       142,154       117,606       161,869  
Net income
    112,045       142,154       117,606       161,869  
 
                               
Income per unit before change in accounting principle:
                               
Basic
  $ 0.20     $ 0.26     $ 0.20     $ 0.30  
Diluted
  $ 0.20     $ 0.26     $ 0.20     $ 0.30  
Net income per unit:
                               
Basic
  $ 0.20     $ 0.26     $ 0.20     $ 0.30  
Diluted
  $ 0.20     $ 0.26     $ 0.20     $ 0.30  
 
                               
For the Year Ended December 31, 2006:
                               
Revenues
  $ 3,250,074     $ 3,517,853     $ 3,872,525     $ 3,350,517  
Operating income
    193,500       186,045       274,184       206,323  
Income before change in accounting principle
    132,302       126,295       208,302       132,784  
Net income
    133,777       126,295       208,302       132,781  
 
                               
Income per unit before change in accounting principle:
                               
Basic
  $ 0.28     $ 0.26     $ 0.43     $ 0.25  
Diluted
  $ 0.28     $ 0.26     $ 0.43     $ 0.25  
Net income per unit:
                               
Basic
  $ 0.28     $ 0.26     $ 0.43     $ 0.25  
Diluted
  $ 0.28     $ 0.26     $ 0.43     $ 0.25  
Note 24. Condensed Financial Information of EPO
          EPO conducts substantially all of our business. Currently, we have no independent operations and no material assets outside those of EPO. EPO consolidates the financial statements of Duncan Energy Partners with those of its own.
          We guarantee the debt obligations of EPO, with the exception of the Dixie revolving credit facility, Duncan Energy Partners’ credit facility and the senior subordinated notes assumed in connection with the GulfTerra Merger. If EPO were to default on any debt we guarantee, we would be responsible for full repayment of that obligation. See Note 14 for additional information regarding our consolidated debt obligations.

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          The reconciling items between our consolidated financial statements and those of EPO are insignificant. The following table presents condensed consolidated balance sheet data for EPO at the dates indicated:
                 
    At December 31,
    2007   2006
     
ASSETS
               
Current assets
  $ 2,544,973     $ 1,915,937  
Property, plant and equipment, net
    11,587,264       9,832,547  
Investments in and advances to unconsolidated affiliates, net
    858,339       564,559  
Intangible assets, net
    917,000       1,003,955  
Goodwill
    591,652       590,541  
Deferred tax asset
    3,113       1,632  
Other assets
    112,345       74,103  
     
Total
  $ 16,614,686     $ 13,983,274  
     
LIABILITIES AND PARTNERS’ EQUITY
               
Current liabilities
  $ 3,044,002     $ 1,986,444  
Long-term debt
    6,906,145       5,295,590  
Other long-term liabilities
    95,112       99,845  
Minority interest
    439,854       136,249  
Partners’ equity
    6,129,573       6,465,146  
     
Total
  $ 16,614,686     $ 13,983,274  
     
 
               
Total EPO debt obligations guaranteed by us
  $ 6,686,500     $ 5,314,000  
     
          The following table presents condensed consolidated statements of operations data for EPO for the periods indicated:
                         
    For the Year Ended December 31,
    2007   2006   2005
     
Revenues
  $ 16,950,125     $ 13,990,969     $ 12,256,959  
Costs and expenses
    16,094,248       13,148,530       11,605,923  
Equity in income of unconsolidated affiliates
    29,658       21,565       14,548  
     
Operating income
    885,535       864,004       665,584  
Other expense
    (305,236 )     (231,876 )     (226,075 )
     
Income before provision for income taxes, minority interest and change in accounting principle
    580,299       632,128       439,509  
Provision for income taxes
    (15,317 )     (21,198 )     (8,362 )
     
Income before minority interest and change in accounting principle
    564,982       610,930       431,147  
Minority interest
    (30,737 )     (9,190 )     (5,989 )
     
Income before change in accounting principle
    534,245       601,740       425,158  
Cumulative effect of change in accounting principle
          1,472       (4,208 )
     
Net income
  $ 534,245     $ 603,212     $ 420,950  
     

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Note 25. Subsequent Event
     Enterprise Products 2008 Long-Term Incentive Plan
     On January 29, 2008, the unitholders of Enterprise Products Partners approved the Enterprise Products 2008 Long-Term Incentive Plan (the “Incentive Plan”), which provides for awards of the Partnership’s common units and other rights to the Partnership’s non-employee directors and to consultants and employees of EPCO and its affiliates providing services to the Partnership. Awards under the Incentive Plan may be granted in the form of restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The Incentive Plan will be administered by EPGP’s ACG Committee. Up to 10,000,000 of the Partnership’s common units may be granted as awards under the Incentive Plan, with such amount subject to adjustment as provided for under the terms of the plan.
     The exercise price of unit options or UARs awarded to participants will be determined by the ACG Committee (at its discretion) at the date of grant and may be no less than the fair market value of the option award as of the date of grant. The Incentive Plan may be amended or terminated at any time by the Board of Directors of EPCO or EPGP’s ACG Committee; however, any material amendment, such as a significant increase in the number of units available under the plan or a change in the types of awards available under the plan, would require the approval of the unitholders of the Partnership. The ACG Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the plan in specified circumstances. The Incentive Plan is effective until January 29, 2018 or, if earlier, the time which all available units under the Incentive Plan have been delivered to participants or the time of termination of the plan by EPCO or EPGP’s ACG Committee.
     Enterprise Unit L.P. Long-Term Incentive Plan
          On February 20, 2008, EPCO formed Enterprise Unit L.P. (“Enterprise LP”) to serve as an incentive arrangement for certain employees of EPCO through a “profits interest” in Enterprise LP. On that date, EPCO Holdings, Inc. (“EPCO Holdings”) agreed to contribute $18,000,000 in the aggregate (the “Initial Contribution”) to Enterprise LP and was admitted as the Class A limited partner. Certain key employees of EPCO including our Chief Executive Officer and Chief Financial Officer were issued Class B limited partner interests and admitted as Class B limited partners of Enterprise LP without any capital contribution. As with the awards granted in connection with the other Employee Partnerships, these awards are designed to provide additional long-term incentive compensation for such employees. The profits interest awards (or Class B limited partner interests) in Enterprise LP entitle the holder to participate in the appreciation in value of Enterprise GP Holdings units and our common units and are subject to forfeiture.
          A portion of the fair value of these equity awards will be allocated to us under the EPCO administrative services agreement as a non-cash expense. We will not reimburse EPCO, Enterprise LP or any of their affiliates or partners, through the administrative services agreement or otherwise, for any expenses related to Enterprise LP, including the Initial Contribution by EPCO Holdings.
          The Class B limited partner interests in Enterprise LP that are owned by EPCO employees are subject to forfeiture if the participating employee’s employment with EPCO and its affiliates is terminated prior to February 20, 2014, with customary exceptions for death, disability and certain retirements. The risk of forfeiture associated with the Class B limited partner interests in Enterprise LP will also lapse upon certain change of control events.
          Unless otherwise agreed to by EPCO, EPCO Holdings and a majority in interest of the Class B limited partners of Enterprise LP, Enterprise LP will terminate at the earlier of February 20, 2014 (six years from the date of the agreement) or a change in control of us or Enterprise GP Holdings. Enterprise LP has the following material terms regarding its quarterly cash distribution to partners:
  §   Distributions of cash flow - Each quarter, 100% of the cash distributions received by Enterprise LP from Enterprise GP Holdings and us will be distributed to the Class A limited partner until EPCO Holdings has received an amount equal to the Class A preferred return (as defined below), and any remaining distributions received by Enterprise LP will be distributed to the Class B limited partners. The Class A preferred return equals the Class A capital base (as defined below) multiplied by 5.0% per annum. The Class A limited partner’s capital base equals the amount of any contributions of cash or cash equivalents made by the Class A limited partner to Enterprise LP, plus any unpaid Class A preferred return from prior periods, less any distributions made by Enterprise LP of proceeds from the sale of units owned by Enterprise LP (as described below).
 
  §   Liquidating Distributions - Upon liquidation of Enterprise LP, units having a fair market value equal to the Class A limited partner capital base will be distributed to EPCO Holdings, plus any accrued Class A preferred return for the quarter in which liquidation occurs. Any remaining units will be distributed to the Class B limited partners.
 
  §   Sale Proceeds - If Enterprise LP sells any units that it beneficially owns, the sale proceeds will be distributed to the Class A limited partner and the Class B limited partners in the same manner as liquidating distributions described above.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
          None.
Item 9A. Controls and Procedures.
Disclosure controls and procedures
          Our management, with the participation of the chief executive officer (“CEO”) and chief financial officer (“CFO”) of our general partner, has evaluated the effectiveness of our disclosure controls and procedures, including internal controls over financial reporting, as of December 31, 2007. This evaluation concluded that our disclosure controls and procedures, including internal controls over financial reporting, are effective to provide us with a reasonable assurance that the information required to be disclosed in reports filed with the SEC is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our management noted no material weaknesses in the design or operation of our internal controls over financial reporting that are likely to adversely affect our ability to record, process, summarize and report financial information. In addition, no fraud involving management or employees who have a significant role in our internal controls over financial reporting was detected.
          The disclosure controls and procedures are also designed to provide reasonable assurance that such information is accumulated and communicated to our management, including the CEO and CFO of our general partner, as appropriate to allow such persons to make timely decisions regarding required disclosures.
          Our management does not expect that our disclosure controls and procedures will prevent all errors and all fraud. The design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Based on the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Enterprise Products Partners have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the controls. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events. Therefore, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Internal control over financial reporting
          Our internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements in accordance with GAAP. These internal controls over financial reporting were designed under the supervision of our management, including the CEO and CFO of our general partner, and include policies and procedures that:
  (i)   pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets,
 
  (ii)   provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
 
  (iii)   provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

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          In accordance with Item 308 of SEC Regulation S-K, management is required to provide an annual report regarding internal controls over our financial reporting. This report, which includes management’s assessment of the effectiveness of our internal controls over financial reporting, is found elsewhere in this Item 9A.
          There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) or in other factors during the fourth quarter of 2007, that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.
          The certifications of our general partner’s CEO and CFO required under Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been included as exhibits to this annual report on Form 10-K.

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING AS OF DECEMBER 31, 2007
          The management of Enterprise Products Partners L.P. and its consolidated subsidiaries, including its Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal control system was designed to provide reasonable assurance to Enterprise Products Partners’ management and board of directors regarding the preparation and fair presentation of published financial statements. However, our management does not represent that our disclosure controls and procedures or internal controls over financial reporting will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only a reasonable, not an absolute, assurance that the objectives of the control system are met.
          Our management assessed the effectiveness of Enterprise Products Partners’ internal control over financial reporting as of December 31, 2007. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework. This assessment included design effectiveness and operating effectiveness of internal controls over financial reporting as well as the safeguarding of assets. Based on our assessment, we believe that, as of December 31, 2007, Enterprise Products Partners’ internal control over financial reporting is effective based on those criteria.
          Our Audit, Conflicts and Governance Committee is composed of directors who are not officers or employees of our general partner. It meets regularly with members of management, the internal auditors and the representatives of the independent registered public accounting firm to discuss the adequacy of Enterprise Products Partners’ internal controls over financial reporting, financial statements and the nature, extent and results of the audit effort. Management reviews with the Audit, Conflicts and Governance Committee all of Enterprise Products Partners’ significant accounting policies and assumptions affecting the results of operations. Both the independent registered public accounting firm and internal auditors have direct access to the Audit, Conflicts and Governance Committee without the presence of management.
     Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. That report is included under Item 9A of this annual report.
          Pursuant to the requirements of Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended, this Annual Report on Internal Control Over Financial Reporting has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on February 29, 2008.
                     
/s/ Michael A. Creel       /s/ W. Randall Fowler    
             
Name:
  Michael A. Creel       Name:   W. Randall Fowler    
Title:
  Chief Executive Officer of our
general partner,
Enterprise Products GP, LLC
      Title:   Chief Financial Officer of our
general partner,
Enterprise Products GP, LLC
   

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of Enterprise Products GP, LLC and
Unitholders of Enterprise Products Partners L.P.
Houston, Texas
          We have audited the internal control over financial reporting of Enterprise Products Partners LP and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting as of December 31, 2007. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
          We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
          A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
          Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
          In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
          We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet and the related statements of consolidated operations, consolidated comprehensive income, consolidated cash flows, and consolidated partners’ equity

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as of and for the year ended December 31, 2007 of the Company and our report dated February 28, 2008 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2008
Item 9B. Other Information.
          None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Partnership Management
          As is commonly the case with publicly traded limited partnerships, we do not directly employ any of the persons responsible for the management or operations of our business. These functions are performed by the employees of EPCO pursuant to an administrative services agreement under the direction of the Board of Directors (the “Board”) and executive officers of EPGP. For a description of the administrative services agreement, see “Certain Relationships and Related Transactions — Relationship with EPCO” under Item 13 of this annual report.
          The executive officers of our general partner are elected for one-year terms and may be removed, with or without cause, only by the Board. Our unitholders do not elect the officers or directors of our general partner. Dan. L. Duncan, through his indirect control of EPGP, has the ability to elect, remove and replace at any time, all of the officers and directors of our general partner. Each member of the Board of our general partner serves until such member’s death, resignation or removal. The employees of EPCO who served as directors of EPGP were Messrs. Dan L. Duncan, Michael A. Creel, W. Randall Fowler, Ralph S. Cunningham and Richard H. Bachmann.
          Because we are a limited partnership and meet the definition of a “controlled company” under the listing standards of the NYSE, we are not required to comply with certain requirements of the NYSE. Accordingly, we have elected to not comply with Section 303A.01 of the NYSE Listed Company Manual, which would require that the Board of our general partner be comprised of a majority of independent directors. In addition, we have elected to not comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require that the Board of our general partner maintain a Nominating Committee and a Compensation Committee, each consisting entirely of independent directors.
          Notwithstanding any contractual limitation on its obligations or duties, EPGP is liable for all debts we incur (to the extent not paid by us), except to the extent that such indebtedness or other obligations are non-recourse to EPGP. Whenever possible, EPGP intends to make any such indebtedness or other obligations non-recourse to itself.
          Under our limited partnership agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events any director or officer, or while serving as director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events any person who is or was an employee (other than an officer) or agent of our partnership.

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Corporate Governance
          We are committed to sound principles of governance. Such principles are critical for us to achieve our performance goals, and maintain the trust and confidence of investors, employees, suppliers, business partners and stakeholders.
          A key element for strong governance is independent members of the Board of Directors. Pursuant to the NYSE listing standards, a director will be considered independent if the Board determines that he or she does not have a material relationship with EPGP or us (either directly or as a partner, unitholder or officer of an organization that has a material relationship with EPGP or us). Based on the foregoing, the Board has affirmatively determined that Messrs. Rex C. Ross, Charles M. Rampacek and E. William Barnett are “independent” directors under the NYSE rules.
          As required by the Sarbanes-Oxley Act of 2002, the SEC adopted rules that direct national securities exchanges and associations to prohibit the listing of securities of a public company if its audit committee members do not satisfy a heightened independence standard. In order to meet this standard, members of such audit committees may not receive any consulting fee, advisory fee or other compensation from the public company other than fees for service as a director or committee member and may not be considered an affiliate of the public company. Neither EPGP nor any individual member of its ACG Committee has relied on any exemption in the NYSE rules to establish such individual’s independence. Based on the foregoing criteria, the Board has affirmatively determined that all members of its ACG Committee satisfy this heightened independence requirement.
     Code of Conduct and Ethics and Corporate Governance Guidelines
          EPGP has adopted a “Code of Conduct” that applies to all directors, officers and employees. This code sets out our requirements for compliance with legal and ethical standards in the conduct of our business, including general business principles, legal and ethical obligations, compliance policies for specific subjects, obtaining guidance, the reporting of compliance issues and discipline for violations of the code.
          Our Code of Conduct also establishes policies applicable to our chief executive officer, chief financial officer, principal accounting officer and senior financial and other managers to prevent wrongdoing and to promote honest and ethical conduct, including ethical handling of actual and apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting of violations of the code.
          Governance guidelines, together with committee charter, provide the framework for effective governance. The Board has adopted the Governance Guidelines of Enterprise Products Partners, which address several matters, including qualifications for directors, responsibilities of directors, retirement of directors, the composition and responsibility of ACG Committee, the conduct and frequency of board and committee meetings, management succession, director access to management and outside advisors, director compensation, director orientation and continuing education, and annual self-evaluation of the board. The Board recognizes that effective governance is an on-going process, and thus, the Board will review the Governance Guidelines of Duncan Energy Partners annually or more often as deemed necessary.
          We provide access through our website at www.epplp.com to current information relating to governance, including the Code of Conduct, the Governance Guidelines of Enterprise Products Partners and other matters impacting our governance principles. You may also contact our investor relations department at (866) 230-0745 for printed copies of these documents free of charge.
     ACG Committee
          The sole committee of the Board is its ACG Committee. In accordance with NYSE rules and Section 3(a)(58)(A) of the Securities Exchange Act of 1934, the Board has named three of its members to

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    serve on its ACG Committee. The members of the ACG Committee are independent directors, free from any relationship with us or any of our subsidiaries that would interfere with the exercise of independent judgment.
          The members of the ACG Committee must have a basic understanding of finance and accounting and be able to read and understand fundamental financial statements, and at least one member of the ACG Committee shall have accounting or related financial management expertise. The members of the ACG Committee are Messrs. Ross, Rampacek and Barnett. The Board has affirmatively determined that Mr. Rampacek satisfies the definition of “audit committee financial expert” as defined in Item 401(h) of Regulation S-K promulgated by the SEC.
          The ACG Committee’s duties are addressing audit and conflicts-related items and general corporate governance. From an audit and conflicts standpoint, the primary responsibilities of the ACG Committee include:
  §   review potential conflicts of interest, including related party transactions;
 
  §   monitoring the integrity of our financial reporting process and related systems of internal control;
 
  §   ensuring our legal and regulatory compliance and that of EPGP;
 
  §   overseeing the independence and performance of our independent public accountant;
 
  §   approving all services performed by our independent public accountant;
 
  §   providing for an avenue of communication among the independent public accountant, management, internal audit function and the Board;
 
  §   encouraging adherence to and continuous improvement of our policies, procedures and practices at all levels;
 
  §   reviewing areas of potential significant financial risk to our businesses; and
 
  §   approving awards granted under our long-term incentive plans.
          If the Board believes that a particular matter presents a conflict of interest and proposes a resolution, the ACG Committee has the authority to review such matter to determine if the proposed resolution is fair and reasonable to us. Any matters approved by the ACG Committee are conclusively deemed to be fair and reasonable to our business, approved by all of our partners and not a breach by EPGP or the Board of any duties they may owe us or our unitholders.
          Pursuant to its formal written charter, the ACG Committee has the authority to conduct any investigation appropriate to fulfilling its responsibilities, and it has direct access to our independent public accountants as well as any EPCO personnel whom it deems necessary in fulfilling its responsibilities. The ACG Committee has the ability to retain, at our expense, special legal, accounting or other consultants or experts it deems necessary in the performance of its duties.
          From a governance standpoint, the ACG Committee’s primary duties and responsibilities are to develop and recommend to the Board a set of governance principles applicable to us and review such guidelines from time to time, making any changes that the ACG Committee deems necessary. The ACG Committee assists the Board in fulfilling its oversight responsibilities.
          A copy of the ACG Committee charter is available on our website, www.epplp.com. You may also contact our investor relations department at (866) 230-0745 for a printed copy of this document free of charge.

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     NYSE Corporate Governance Listing Standards
          On April 2, 2007, Robert G. Phillips, our chief executive officer on such date, certified to the NYSE (as required by Section 303A.12(a) of the NYSE Listed Company Manual) that he was not aware of any violation by us of the NYSE’s Corporate Governance listing standards as of April 2, 2007.
Executive Sessions of Non-Management Directors
          The Board holds regular executive sessions in which non-management directors meet without any members of management present. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. During such executive sessions, one director is designated as the “presiding director,” who is responsible for leading and facilitating such executive sessions. Currently, the presiding director is Mr. Barnett.
          In accordance with NYSE rules, we have established a toll-free, confidential telephone hotline (the “Hotline”) so that interested parties may communicate with the presiding director or with all the non-management directors as a group. All calls to this Hotline are reported to the chairman of the ACG Committee, who is responsible for communicating any necessary information to the other non-management directors. The number of our confidential Hotline is (877) 888-0002.
Directors and Executive Officers of EPGP
          The following table sets forth the name, age and position of each of the directors and executive officers of EPGP at February 29, 2008. Each executive officer holds the same respective office shown below in the general partner of the Operating Partnership.
             
Name   Age   Position with EPGP
 
Dan L. Duncan (1)
    75     Director and Chairman
Michael A. Creel (1)
    54     Director, President and Chief Executive Officer
W. Randall Fowler (1)
    51     Director, Executive Vice President and Chief Financial Officer
Richard H. Bachmann (1)
    55     Director, Executive Vice President, Chief Legal Officer and Secretary
Dr. Ralph S. Cunningham
    67     Director
E. William Barnett (2,3)
    75     Director
Rex C. Ross (2)
    64     Director
Charles M. Rampacek (2)
    64     Director
William Ordemann (1)
    48     Executive Vice President and Chief Operating Officer
James H. Lytal (1)
    50     Executive Vice President
A.J. Teague (1)
    62     Executive Vice President
Gil H. Radtke
    46     Senior Vice President
James M. Collingsworth
    53     Senior Vice President
Michael J. Knesek (1)
    53     Senior Vice President, Controller and Principal Accounting Officer
 
(1)   Executive officer
 
(2)   Member of ACG Committee
 
(3)   Chairman of ACG Committee
          The following information presents a brief history of the business experience of our directors and executive officers serving as of December 31, 2007:
          Dan L. Duncan. Mr. Duncan was elected Chairman and a Director of EPGP in April 1998, Chairman and a Director of the general partner of EPO in December 2003, Chairman and a Director of EPE Holdings in August 2005 and Chairman and a Director of DEP GP in October 2006. Mr. Duncan served as the sole Chairman of EPCO from 1979 to December 2007. Mr. Duncan now serves as Group Co-Chairman of EPCO with his daughter, Ms. Randa Duncan Williams, also a Director of EPE Holdings. He also serves as a Honorary Trustee of the Board of Trustees of the Texas Heart Institute at Saint Luke’s Episcopal Hospital.

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          Michael A. Creel. Mr. Creel was elected President and Chief Executive Officer of EPGP in August 2007. From June 2000 to August 2007, Mr. Creel served as Chief Financial Officer of EPGP and an Executive Vice President of EPGP from January 2001 to August 2007. Mr. Creel, a certified public accountant, also served as a Senior Vice President of EPGP from November 1999 to January 2001.
          In December 2007, Mr. Creel was elected Group Vice Chairman and Chief Financial Officer of EPCO. Prior to these elections in EPCO, Mr. Creel served as Chief Operating Officer from April 2005 to December 2007 and Chief Financial Officer from June 2000 to April 2005 for EPCO. He also serves as a Director of DEP GP and EPGP since October 2006 and 2005, respectively. Mr. Creel served as President, Chief Executive Officer and a Director of EPE Holdings from August 2005 through August 2007. In October 2005, Mr. Creel was elected a Director of Edge Petroleum Corporation (a publicly traded oil and natural gas exploration and production company).
          W. Randall Fowler. Mr. Fowler was elected Executive Vice President and Chief Financial Officer of EPGP, EPE Holdings and DEP GP in August 2007. Mr. Fowler has served as Senior Vice President and Treasurer of EPGP from February 2005 to August 2007 and of DEP GP from October 2006 to August 2007. In February 2006, Mr. Fowler became a Director of EPGP and EPE Holdings and of DEP GP since October 2006. Mr. Fowler also served as Senior Vice President and Chief Financial Officer of EPE Holdings from August 2005 to August 2007.
          Mr. Fowler was elected President and Chief Executive Officer of EPCO in December 2007. Prior to these elections, he served as Chief Financial Officer of EPCO from April 2005 to December 2007. Mr. Fowler, a certified public accountant (inactive), joined Enterprise Products Partners as Director of Investor Relations in January 1999.
          Richard H. Bachmann. Mr. Bachmann was elected an Executive Vice President, Chief Legal Officer and Secretary of EPGP and a Director of EPGP in February 2006. He previously served as a Director of EPGP from June 2000 to January 2004. Mr. Bachmann has served as a Director of the general partner of EPO since December 2003 and has served as Executive Vice President, Chief Legal Officer and Secretary of EPE Holdings since August 2005.
          Mr. Bachmann was elected Group Vice Chairman, Chief Legal Officer and Secretary of EPCO in December 2007. In October 2006, Mr. Bachmann was elected President, Chief Executive Officer and a Director of DEP GP. Mr. Bachmann was also elected a Director of DEP GP in October 2006 and a Director of EPE Holdings in February 2006. Since January 1999, Mr. Bachmann has served as a Director of EPCO. In November 2006, Mr. Bachmann was appointed an independent manager of Constellation Energy Partners LLC. Mr. Bachmann also serves as a member of the audit, compensation and nominating and governance committee of Constellation Energy Partners LLC.
          Dr. Ralph S. Cunningham. Dr. Cunningham was elected a Director of EPGP in February 2006 and also served as a Director of EPGP from 1998 until March 2005. In addition to these duties Dr. Cunningham served as Group Executive Vice President and Chief Operating Officer of EPGP from December 2005 to August 2007 and Interim President and Interim Chief Executive Officer from June 2007 to August 2007. Dr. Cunningham was elected President and Chief Executive Officer of EPE Holdings in August 2007. He served as Chairman and a Director of TEPPCO GP from March 2005 until November 2005.
          Dr. Cunningham was elected a Group Vice Chairman of EPCO in December 2007 and served as a Director from 1987 to 1997. He serves as a Director of Tetra Technologies, Inc. (a publicly traded energy services and chemical company), EnCana Corporation (a Canadian publicly traded independent oil and natural gas company) and Agrium, Inc. (a Canadian publicly traded agricultural chemicals company). Dr. Cunningham retired in 1997 from CITGO Petroleum Corporation, where he had served as President and Chief Executive Officer since 1995.
          E. William Barnett. Mr. Barnett was elected a Director of EPGP in March 2005. Mr. Barnett is a member of our ACG Committee and serves as its Chairman. Mr. Barnett practiced law with Baker Botts

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L.L.P. from 1958 until his retirement in 2004. In 1984, he became Managing Partner of Baker Botts L.L.P. and continued in that role for fourteen years until 1998. He was Senior Counsel to the firm from 1998 until June 2004, when he retired from the firm. Mr. Barnett served as Chairman of the Board of Trustees of Rice University from 1996 to July 2005.
          Mr. Barnett is a Life Trustee of The University of Texas Law School Foundation; a Director of St. Luke’s Episcopal Health System; and a Director and former Chairman of the Houston Zoo, Inc. (the operating arm of the Houston Zoo). He is a Director of Reliant Energy, Inc. (a publicly traded electric services company) and Westlake Chemical Corporation (a publicly traded chemical company). Mr. Barnett is Chairman of the Advisory Board of the Baker Institute for Public Policy at Rice University and a Director and former Chairman of the Greater Houston Partnership. Mr. Barnett served as a Trustee of the Baylor College of Medicine from 1993 until 2004.
          Rex C. Ross. Mr. Ross was elected a Director of EPGP in October 2006 and is a member of its ACG Committee. Mr. Ross serves as a Director of Schlumberger Technology Corporation, the holding company for all Schlumberger Limited assets and entities in the United States. Prior to his executive retirement from Schlumberger Limited in May 2004, Mr. Ross held a number of executive management positions during his 11-year career with the company, including President of Schlumberger Oilfield Services North America; President, Schlumberger GeoQuest; and President of SchlumbergerSema North & South America. Mr. Ross also serves on the board of directors of Gulfmark Offshore, Inc. (a publicly traded offshore marine services company) and is a member of its Governance Committee.
          Charles M. Rampacek. Mr. Rampacek was elected a Director of EPGP in October 2006 and is a member of its ACG Committee. Mr. Rampacek is currently a business and management consultant in the energy industry. Mr. Rampacek served as Chairman, Chief Executive Officer and President of Probex Corporation (“Probex”), an energy technology company that developed a proprietary used oil recovery process, from 2000 until his retirement in 2003. Prior to joining Probex Corporation, Mr. Rampacek was President and Chief Executive Officer of Lyondell-Citgo Refining L.P, a manufacturer of petroleum products, from 1996 through 2000. From 1982 to 1995, he held various executive positions with Tenneco Inc. and its energy-related subsidiaries, including President of Tenneco Gas Transportation Company, Executive Vice President of Tenneco Gas Operations and Senior Vice President of Refining and Supply. Mr. Rampacek also spent 16 years with Exxon Company USA, where he held various supervisory and management positions. Mr. Rampacek has been a Director of Flowserve Corporation since 1998 and is Chairman of its Corporate Governance and Nominating Committee and a member of its Organization and Compensation Committee.
          In 2005, two complaints requesting recovery of certain costs were filed against former officers and directors of Probex Corporation as a result of the bankruptcy of Probex in 2003. These complaints were defended under Probex’s director and officer insurance by AIG and settlement was reached and paid by AIG with bankruptcy court approval in the first half of 2006. An additional complaint was filed in 2005 against noteholders of certain Probex debt of which Mr. Rampacek was one. A settlement of $2,000 was reached and approved by the bankruptcy court in the first half of 2006.
          William Ordemann. Mr. Ordemann was elected an Executive Vice President and the Chief Operating Officer of EPGP in August 2007. He previously served as a Senior Vice President of EPGP from September 2001 to August 2007 and was a Vice President of EPGP from October 1999 to September 2001. Mr. Ordemann joined us in connection with our purchase of certain midstream energy assets from affiliates of Shell Oil Company in 1999. Prior to joining us, he was a Vice President of Shell Midstream Enterprises, LLC from January 1997 to February 1998, and Vice President of Tejas Natural Gas Liquids, LLC from February 1998 to September 1999.
          James H. Lytal. Mr. Lytal was elected an Executive Vice President of EPGP in September 2004. Mr. Lytal served as a Director of the general partner of GulfTerra Energy Partners, L.P. from August 1994 until September 2004, and as President of GulfTerra and its general partner from July 1995 until September 2004. He served as a Senior Vice President of GulfTerra and its general partner from August 1994 to June 1995. Prior to joining GulfTerra, Mr. Lytal served in various capacities with the oil and gas exploration

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and production and natural gas pipeline businesses of United Gas Pipeline Company, Texas Oil and Gas, Inc. and American Pipeline Company
          A.J. Teague. Mr. Teague was elected an Executive Vice President of EPGP in November 1999. Mr. Teague joined us in connection with our purchase of certain midstream energy assets from affiliates of Shell Oil Company in 1999. From 1998 to 1999, Mr. Teague served as President of Tejas Natural Gas Liquids, LLC
          Gil H. Radtke. Mr. Radtke was elected a Senior Vice President of EPGP in February 2002. Mr. Radtke joined us in connection with our purchase of Diamond-Koch’s storage and propylene fractionation assets in 2002. Before joining us, Mr. Radtke served as president of the Diamond-Koch joint venture from 1999 to 2002, where he was responsible for its storage, propylene fractionation, pipeline and NGL fractionation businesses. From 1997 to 1999 he was Vice President, Petrochemicals and Storage of Diamond-Koch. In October 2006, Mr. Radtke was elected a Senior Vice President, Chief Operating Officer and a Director of the general partner of Duncan Energy Partners.
          James M. Collingsworth. Mr. Collingsworth was elected a Vice President of EPGP in November 2001 and subsequently promoted to a Senior Vice President in November 2002. Mr. Collingsworth joined us in connection with our acquisition of the Mid-America and Seminole Pipeline Systems in 2002. Before joining us, he served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991 to 2001 in various management positions, including Senior Vice President of NGL Assets and Business Services from July 1998 to October 2001.
          Michael J. Knesek. Mr. Knesek, a certified public accountant, was elected a Senior Vice President of EPGP in February 2005 having served as a Vice President of EPGP since August 2000. Mr. Knesek has been the Principal Accounting Officer and Controller of EPGP since August 2000, EPE Holdings since August 2005 and DEP GP since October 2006. He has served as Senior Vice President of EPE Holdings since August 2005 and of DEP GP since October 2006. Mr. Knesek has been the Controller of EPCO since 1990 and currently serves as one of its Senior Vice Presidents.
Section 16(a) Beneficial Ownership Reporting Compliance
          Under federal securities laws, EPGP, directors and executive officers of EPGP, and certain other officers, and any persons holding more than 10% of our common units are required to report their ownership of common units and any changes in their ownership levels to us and the SEC. Specific due dates for these reports have been established by regulation, and we are required to disclose in this annual report any failure to file this information within the specified timeframes. With the exception of the following late filing, all such reporting was done in a timely manner in 2007.
          The spouse of Mr. Rex Ross serves as trustee for a trust that benefits, in part, certain of his immediate family members. This trust holds 4,500 common units of Enterprise that have not been previously reported for Section 16 purposes. On November 14, 2007, this trust purchased 1,000 common units of Enterprise at an average price of $31.95 per unit. The remaining 3,500 common units held in the trust were purchased more than six months before Mr. Ross became a Director of EPGP and should have been reflected on his Form 3, which was filed on October 23, 2006. These trust holdings were properly reflected on a Form 4 for Mr. Ross on Friday, February 29, 2008.
Item 11. Executive Compensation.
Executive Officer Compensation
          We do not directly employ any of the persons responsible for managing our partnership. Instead, we are managed by our general partner, the executive officers of which are employees of EPCO. Our reimbursement of EPCO’s compensation costs is governed by the administrative services agreement with EPCO (see Item 13).

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     Summary Compensation Table
          The following table presents consolidated compensation amounts paid, accrued or otherwise expensed by us with respect to the years ended December 31, 2007 and 2006 for our general partner’s Chief Executive Officer (“CEO”), Chief Financial Officer (“CFO”) and three other most highly compensated executive officers as of December 31, 2007. We also include Robert G. Phillips and Dr. Ralph S. Cunningham, both of whom served as our CEO during 2007 prior to Michael A. Creel’s appointment to this position effective August 1, 2007. Collectively, these seven individuals were our “Named Executive Officers” for 2007. Compensation paid or awarded by us with respect to such Named Executive Officers reflects only that portion of compensation paid by EPCO allocated to us pursuant to an administrative services agreement, including an allocation of a portion of the cost of EPCO’s equity-based long-term incentive plans.
                                                         
Name and                           Unit   Option   All Other    
Principal           Salary   Bonus   Awards   Awards   Compensation   Total
Position   Year   ($)   ($) (5)   ($) (6)   ($) (7)   ($) (8)   ($)
 
Michael A. Creel (1)
    2007     $ 361,808     $ 365,370     $ 517,707     $ 44,449     $ 108,017     $ 1,397,351  
 
    2006       306,000       125,000       303,622       23,613       71,812       830,047  
 
                                                       
Robert G. Phillips (former CEO) (2)
    2007       372,300             202,755       166,498       8,950,109       9,691,662  
 
    2006       722,500       300,000       660,270       357,209       150,984       2,190,963  
 
                                                       
Dr. Ralph S. Cunningham (former CEO) (3)
    2007       281,828       171,190       231,645       23,564       37,896       746,123  
 
    2006       478,667       250,000       52,815       13,707       33,208       828,397  
 
                                                       
W. Randall Fowler (4)
    2007       213,145       129,720       297,976       25,033       53,425       719,299  
 
    2006       215,875       70,000       173,874       14,242       40,601       514,592  
 
                                                       
James H. Lytal
    2007       386,250       210,000       730,634       77,980       162,494       1,567,358  
 
    2006       367,500       187,500       455,462       47,227       101,639       1,159,328  
 
                                                       
A. J. Teague
    2007       445,660       300,000       587,905       77,980       110,336       1,521,881  
 
    2006       428,480       250,000       299,984       47,227       69,563       1,095,254  
 
                                                       
Richard H. Bachmann
    2007       306,900       186,000       454,130       38,990       94,752       1,080,772  
 
    2006       177,420       75,000       182,174       14,168       43,088       491,850  
 
(1)   Mr. Creel was appointed our Chief Executive Officer effective August 1, 2007. He served as our Chief Financial Officer through August 1, 2007. Amounts presented for the years ended December 31, 2007 and 2006 reflect his tenure in both positions.
 
(2)   Mr. Phillips served as our Chief Executive Officer until his resignation effective June 30, 2007. The amount presented as “All Other Compensation” for 2007 includes a separation payment of $8,822,400.
 
(3)   Dr. Cunningham served as our Acting Chief Executive Officer from June 30, 2007 to August 1, 2007. Amounts presented for the years ended December 31, 2007 and 2006 reflect his total compensation allocated to us with respect to these periods.
 
(4)   Mr. Fowler was appointed our Chief Financial Officer effective August 1, 2007. Amounts presented for the years ended December 31, 2007 and 2006 reflect his total compensation allocated to us with respect to these periods.
 
(5)   Amounts represent discretionary annual cash awards accrued for the years ended December 31, 2007 and 2006. Cash awards are paid in February of the following year (e.g. 2007 cash awards are paid in February 2008).
 
(6)   Amounts represent expense recognized in accordance with SFAS 123(R) for the years ended December 31, 2007 and 2006 with respect to restricted unit and Employee Partnership awards.
 
(7)   Amounts represent expense recognized in accordance with SFAS 123(R) for the years ended December 31, 2007 and 2006 with respect to unit options.
 
(8)   Amounts primarily represent (i) matching contributions under funded, qualified, defined contribution retirement plans, (ii) quarterly distributions paid on equity incentive plan awards and (iii) the imputed value of life insurance premiums paid on behalf of the officer.
 
(9)   Mr. Lytal’s total compensation for 2007 includes perquisites totaling $13,111.

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     Compensation Discussion and Analysis
          With respect to our Named Executive Officers, compensation paid or awarded by us for the last two fiscal years reflects only that portion of compensation paid by EPCO allocated to us pursuant to the administrative services agreement, including an allocation of a portion of the cost of equity-based long-term incentive plans of EPCO. Dan L. Duncan controls EPCO and has ultimate decision-making authority with respect to the compensation of our Named Executive Officers. The following elements of compensation, and EPCO’s decisions with respect to determination of payments, are not subject to approvals by our Board or the ACG Committee. Awards under EPCO’s long-term incentive plans are approved by the ACG Committee. We do not have a separate compensation committee.
          As discussed below, the elements of EPCO’s compensation program, along with EPCO’s other rewards (e.g., benefits, work environment, career development), are intended to provide a total rewards package to employees. The compensation package is designed to reward contributions by employees in support of the business strategies of EPCO and its affiliates at both the partnership and individual levels. With respect to the years ended December 31, 2007 and 2006, EPCO’s compensation package for Named Executive Officers did not include any elements based on targeted performance-related criteria.
          The primary elements of EPCO’s compensation program are a combination of annual cash and long-term equity-based incentive compensation. For the years ended December 31, 2007 and 2006, the elements of compensation for the Named Executive Officers consisted of the following:
  §   Annual base salary;
 
  §   Discretionary annual cash awards;
 
  §   Awards under long-term incentive arrangements; and
 
  §   Other compensation, including very limited perquisites.
          In order to assist Mr. Duncan and EPCO with compensation decisions, our Chief Executive Officer and the Senior Vice President of Human Resources for EPCO formulate preliminary compensation recommendations for all of the Named Executive Officers other than our Chief Executive Officer. Mr. Duncan, after consulting with the Senior Vice President of Human Resources for EPCO, independently makes compensation decisions with respect to our Chief Executive Officer. EPCO takes note of market data for determining relevant compensation levels and compensation program elements through the review of and, in certain cases, participation in, various relevant compensation surveys. Mr. Duncan and EPCO do not use any formula or specific performance-based criteria for our Named Executive Officers in connection with services performed for us. All compensation determinations are discretionary and, as noted above, subject to Mr. Duncan’s ultimate decision-making authority.
          The discretionary cash awards paid to each of our Named Executive Officers were determined by consultation among Mr. Duncan, our Chief Executive Officer and the Senior Vice President of Human Resources for EPCO, subject to Mr. Duncan’s final determination. These cash awards, in combination with annual base salaries, are intended to yield competitive total cash compensation levels for the Named Executive Officers and drive performance in support of our business strategies, as well as the performance of other EPCO affiliates for which the Named Executive Officers perform services. It is EPCO’s general policy to pay these awards during the first quarter of each year.
           The equity awards granted under the EPCO 1998 Plan to our Named Executive Officers were determined by consultation among Mr. Duncan, our Chief Executive Officer and the Senior Vice President of Human Resources for EPCO, and were approved by our general partner’s ACG Committee. These awards (restricted units and unit options) are intended to align the long-term interests of the executive officers with those of our unitholders. It is EPCO’s general policy to recommend, and the ACG Committee typically approves, these grants to employees during the second quarter of each fiscal year. In addition, our Named Executive Officers are Class B limited partners in certain of the Employee Partnerships. Mr. Duncan approves the issuance of all limited partnership interests in such Employee Partnerships to our Named Executive Officers. See “Summary of Long-Term Incentive Arrangements Underlying 2007 Award Grants” within this Item 11 for information regarding the long-term incentive plans. See Notes 2 and 5 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding the accounting for such awards.

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          EPCO generally does not pay for perquisites for any of our Named Executive Officers, other than reimbursement of certain parking expenses, and expects to continue its policy of covering very limited perquisites allocable to our Named Executive Officers. EPCO also makes matching contributions under its 401(k) plan for the benefit of our Named Executive Officers in the same manner as it does for other EPCO employees.
          EPCO does not offer our Named Executive Officers a defined benefit pension plan. Also, none of our Named Executive Officers had nonqualified deferred compensation during the years ended December 31, 2007 or 2006.
          We believe that each of the base salary, cash awards, and incentive awards fit the overall compensation objectives of us and of EPCO, as stated above (i.e., to provide competitive compensation opportunities to align and drive employee performance toward the creation of sustained long-term unitholder value, which will also allow us to attract, motivate and retain high quality talent with the skills and competencies required by us).
Compensation Committee Report
           We do not have a separate compensation committee. As discussed in the Compensation Discussion and Analysis, we do not directly employ or compensate our Named Executive Officers. Rather, under the administrative services agreement with EPCO, we reimburse EPCO for the compensation of our executive officers. Accordingly, to the extent that decisions are made regarding the compensation policies pursuant to which our Named Executive Officers are compensated, they are made by Dan L. Duncan and EPCO (except for equity awards under long-term incentive plans, as discussed above), and not by our Board of Directors.
           In light of the foregoing, the Board of Directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis with management. Based on our review of and discussion with management with respect to the Compensation Discussion and Analysis, we determined that the Compensation Discussion and Analysis be included in this Report.
Submitted by:      Dan L. Duncan
Michael A. Creel
W. Randall Fowler
Richard H. Bachmann
Dr. Ralph S. Cunningham
E. William Barnett
Charles M. Rampacek
Rex C. Ross
           Notwithstanding anything to the contrary set forth in any previous filings under the Securities Act, as amended, or the Exchange Act, as amended, that incorporate future filings, including this Report, in whole or in part, the foregoing report shall not be incorporated by reference into any such filings.

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     Grants of Plan-Based Awards in Fiscal Year 2007
          The following table presents information concerning each grant of a plan-based award made to a Named Executive Officer in 2007. The restricted unit and unit option awards granted during 2007 were under EPCO’s 1998 Long-Term Incentive Plan (the “1998 Plan”). See “Summary of Long-Term Incentive Arrangements Underlying 2007 Award Grants” within this Item 11 for additional information regarding EPCO’s long-term incentive plans.
                                                 
                                            Grant
                                    Exercise   Date Fair
                                    or Base   Value of
            Estimated Future Payouts Under   Price of   Unit and
            Equity Incentive Plan Awards   Option   Option
    Grant   Threshold   Target   Maximum   Awards   Awards
Name   Date   (#)   (#)   (#)   ($/Unit)   ($) (1)
Restricted unit awards: (2)
                                               
Michael A. Creel
    5/29/07             26,500                 $ 481,926  
Dr. Ralph S. Cunningham
    5/29/07             26,500                   434,812  
W. Randall Fowler
    5/29/07             17,000                   235,686  
James H. Lytal
    5/29/07             26,500                   820,440  
A.J. Teague
    5/29/07             26,500                   820,440  
Richard H. Bachmann
    5/29/07             26,500                   341,697  
Unit option awards: (3)
                                               
Michael A. Creel
    5/29/07             60,000           $ 30.96       94,454  
Dr. Ralph S. Cunningham
    5/29/07             60,000           $ 30.96       85,224  
W. Randall Fowler
    5/29/07             45,000           $ 30.96       54,005  
James H. Lytal
    5/29/07             60,000           $ 30.96       160,800  
A.J. Teague
    5/29/07             60,000           $ 30.96       160,800  
Richard H. Bachmann
    5/29/07             60,000           $ 30.96       66,973  
EPE Unit III profits interest award: (4)
                                               
Michael A. Creel
    5/7/07                               1,032,387  
Dr. Ralph S. Cunningham
    5/7/07                               931,504  
W. Randall Fowler
    5/7/07                               787,033  
James H. Lytal
    5/7/07                               1,464,621  
A.J. Teague
    5/7/07                               1,464,621  
Richard H. Bachmann
    5/7/07                               732,021  
 
(1)   Amounts presented reflect that portion of grant date fair value allocable to us based on the percentage of time each Named Executive Officer spent on our consolidated business activities during 2007. Based on current allocations, we estimate that the consolidated compensation expense we record for each Named Executive Officer with respect to these awards will equal these amounts over time.
 
(2)   For the period in which the restricted unit awards were outstanding during 2007, we recognized a total of $0.4 million of consolidated compensation expense related to these awards. The remaining portion of grant date fair value will be recognized as expense in future periods.
 
(3)   For the period in which the unit option awards were outstanding during 2007, we recognized a total of $72 thousand of consolidated compensation expense related to these awards. The remaining portion of grant date fair value will be recognized as expense in future periods.
 
(4)   For the period in which the profits interest awards were outstanding during 2007, we recognized a total of $1.0 million of consolidated compensation expense related to these awards. The remaining portion of grant date fair value will be recognized as expense in future periods.
          The fair value amounts shown in the preceding table are based on certain assumptions and considerations made by management. The grant date fair values of restricted unit awards issued in May 2007 were based on a market price of Enterprise Products Partners’ common units of $30.96 per unit.
          The grant date fair values of unit option awards issued in May 2007 were based on the following assumptions: (i) expected life of the options of seven years; (ii) risk-free interest rate of 4.8%; (iii) an expected distribution yield on our common units of 8.4%; and (iv) an expected unit price volatility of our common units of 23.2%.

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          The fair value of the EPE Unit III profits interest awards issued in May 2007 was based on the following assumptions: (i) remaining life of the award of five years; (ii) risk-free interest rate of 4.6%; (iii) an expected distribution yield on Enterprise GP Holdings’ units of 4.1% and (iv) an expected unit price volatility of Enterprise GP Holdings’ units of 17.6%.
          Awards granted to Robert G. Phillips in May 2007 were cancelled in connection with his $8.8 million cash separation payment paid in June 2007.
     Summary of Long-Term Incentive Arrangements Underlying 2007 Award Grants
           The following information summarizes the types of awards granted to our Named Executive Officers during the year ended December 31, 2007. For detailed information regarding our accounting for unit-based awards, see Note 5 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
          Unit option awards. Under EPCO’s 1998 Plan, non-qualified, incentive options to purchase a fixed number of our common units may be granted to EPCO’s key employees who perform management, administrative or operational functions for us or our affiliates. When issued, the exercise price of each option grant is equivalent to the market price of the underlying equity on the date of grant. In general, options granted under the 1998 Plan have a vesting period of four years and remain exercisable for ten years from the date of grant. In order to fund its obligations under the 1998 Plan, EPCO may purchase common units at fair value either in the open market or directly from us. When employees exercise unit options, we reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the units issued to the employee.
          Restricted unit awards. Under the 1998 Plan, EPCO’s key employees who perform management, administrative or operational functions for us or our affiliates may be awarded restricted common units. In general, our restricted unit awards allow recipients to acquire the underlying common units (at no cost to the recipient) once a defined vesting period expires, subject to certain forfeiture provisions. The restrictions on such nonvested units generally lapse four years from the date of grant. The fair value of restricted units is based on the market price of the underlying common units on the date of grant less an allowance for estimated forfeitures. Each recipient is also entitled to cash distributions equal to the product of the number of restricted units outstanding for the participant and the cash distribution per unit paid by us to our unitholders.
           As used in the context of the EPCO plans, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires.
          Phantom unit awards. The EPCO 1998 Plan also provides for the issuance of phantom unit awards. These liability awards are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at redemption dates in each award. The fair market value of each phantom unit award is equal to the market closing price of our common units on the redemption date. Each participant is required to redeem their phantom units as they vest, which typically is four years from the date the award is granted. No phantom unit awards have been issued to date under the EPCO 1998 Plan.
          The EPCO 1998 Plan also provides for the award of distribution equivalent rights (“DERs”) in tandem with its phantom unit awards. A DER entitles the participant to cash distributions equal to the product of the number of phantom units outstanding for the participant and the cash distribution rate paid by us to our unitholders.
          Profits interests awards. EPCO formed the Employee Partnerships to serve as long-term incentive arrangements for certain employees of EPCO by providing “profits interests” in the underlying limited partnerships (i.e. EPE Unit I, EPE Unit II and EPE Unit III). Our Named Executive Officers have been granted profits interest awards in EPE Unit I (formed in August 2005), EPE Unit II (formed in December 2006) and EPE Unit III (formed in May 2007). The profits interest awards (or Class B limited partner interests) entitle each holder to participate in the appreciation in value of Enterprise GP Holdings’ units and are subject to forfeiture. See Item 13 of this annual report for additional information regarding the Employee Partnerships.

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          The following table provides information regarding the Named Executive Officers’ share of such profits interest at December 31, 2007:
                 
            Estimated
    Percentage   Liquidation
    Ownership   Value To Be
    of Class B   Received
Plan Name   Interests (1)   by Officer (2)
 
EPE Unit I: (3)
               
Michael A. Creel
    7.92 %   $ 1,100,679  
W. Randall Fowler
    5.32 %     739,257  
James H. Lytal
    5.32 %     739,257  
A.J. Teague
    5.32 %     739,257  
Richard H. Bachmann
    7.92 %     1,100,679  
EPE Unit II: (4)
               
Dr. Ralph S. Cunningham
    100.0 %   $ 0  
EPE Unit III: (5)
               
Michael A. Creel
    7.63 %   $ 0  
Dr. Ralph S. Cunningham
    7.63 %   $ 0  
W. Randall Fowler
    7.63 %   $ 0  
James H. Lytal
    6.36 %   $ 0  
A.J. Teague
    6.36 %   $ 0  
Richard H. Bachmann
    7.63 %   $ 0  
 
(1)   Reflects Named Executive Officer share of profits interest at December 31, 2007.
 
(2)   Values based on December 31, 2007 closing price of Enterprise GP Holdings’ units of $37.02 per unit and taking into account the terms of liquidation outlined in each Employee Partnership agreement.
 
(3)   At December 31, 2007, the total profits interests of EPE Unit I would have been worth $13.9 million, of which each Named Executive Officer would have received his proportionate share.
 
(4)   The EPE Unit II Class B partnership interest had no liquidation value at December 31, 2007 due to a decrease in the market value of Enterprise GP Holdings’ units since the formation of EPE Unit II.
 
(5)   The EPE Unit III Class B partnership interests had no liquidation value at December 31, 2007 due to a decrease in the market value of Enterprise GP Holdings’ units since the formation of EPE Unit III.
          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 Products 2008 Long-Term Incentive Plan in January 2008 and Enterprise Unit L.P. in February 2008.

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     Equity Awards Outstanding at December 31, 2007
          The following tables present information concerning each Named Executive Officer’s nonvested restricted units and unexercised unit options as of December 31, 2007.
                                                 
            Option Awards   Unit Awards
            Number of                           Market
            Units                   Number   Value
            Underlying   Option           of Units   of Units
            Options   Exercise   Option   That Have   That Have
    Vesting   Unexercisable   Price   Expiration   Not Vested   Not Vested
Name   Date   (#)   ($/Unit)   Date   (#)   ($)
 
Restricted unit awards:
                                               
Michael A. Creel
  Various (1)                       103,053     $ 3,285,330  
Dr. Ralph S. Cunningham
  Various (1)                       38,500       1,227,380  
W. Randall Fowler
  Various (1)                       58,777       1,873,811  
James H. Lytal
  Various (1)                       86,032       2,742,700  
A.J. Teague
  Various (1)                       60,500       1,928,740  
Richard H. Bachmann
  Various (1)                       103,053       3,285,330  
 
                                               
Unit option awards:
                                               
Michael A. Creel:
                                               
May 10, 2004 option grant
    5/10/08       35,000     $ 20.00       5/10/14              
August 4, 2005 option grant
    8/04/09       35,000       26.47       8/04/15              
May 1, 2006 option grant
    5/01/10       40,000       24.85       5/01/16              
May 29, 2007 option grant
    5/29/11       60,000       30.96       5/29/17              
Dr. Ralph S. Cunningham:
                                               
May 1, 2006 option grant
    5/01/10       40,000       24.85       5/01/16              
May 29, 2007 option grant
    5/29/11       60,000       30.96       5/29/17              
W. Randall Fowler:
                                               
May 10, 2004 option grant
    5/10/08       10,000       20.00       5/10/14              
August 4, 2005 option grant
    8/04/09       25,000       26.47       8/04/15              
May 1, 2006 option grant
    5/01/10       40,000       24.85       5/01/16              
May 29, 2007 option grant
    5/29/11       45,000       30.96       5/29/17              
James H. Lytal:
                                               
September 30, 2004 option grant
    9/30/08       35,000       23.18       9/30/14              
August 4, 2005 option grant
    8/04/09       35,000       26.47       8/04/15              
May 1, 2006 option grant
    5/01/10       40,000       24.85       5/01/16              
May 29, 2007 option grant
    5/29/11       60,000       30.96       5/29/17              
A.J. Teague:
                                               
May 10, 2004 option grant
    5/10/08       35,000       20.00       5/10/14              
August 4, 2005 option grant
    8/04/09       35,000       26.47       8/04/15              
May 1, 2006 option grant
    5/01/10       40,000       24.85       5/01/16              
May 29, 2007 option grant
    5/29/11       60,000       30.96       5/29/17              
Richard H. Bachmann:
                                               
May 10, 2004 option grant
    5/10/08       35,000       20.00       5/10/14              
August 4, 2005 option grant
    8/04/09       35,000       26.47       8/04/15              
May 1, 2006 option grant
    5/01/10       40,000       24.85       5/01/16              
May 29, 2007 option grant
    5/29/11       60,000       30.96       5/29/17              
 
(1)   Of the 449,915 restricted units presented in the table, 182,415 vest in 2008, 46,000 vest in 2009, 72,000 vest in 2010, and 149,500 vest in 2011.

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          The following tables present information concerning each Named Executive Officer’s nonvested profits interest awards as of December 31, 2007.
                                                 
            Option Awards     Unit Awards  
            Number of                             Market  
            Units                     Number     Value  
            Underlying     Option             of Units     of Units  
            Options     Exercise     Option     That Have     That Have  
    Vesting     Unexercisable     Price     Expiration     Not Vested     Not Vested  
Name   Date     (#)     ($/Unit)     Date     (#)     ($)  
 
EPE Unit I profits interest awards:
                                               
Michael A. Creel
    8/30/10                               1,100,679  
W. Randall Fowler
    8/30/10                               739,257  
James H. Lytal
    8/30/10                               739,257  
A.J. Teague
    8/30/10                               739,257  
Richard H. Bachmann
    8/30/10                               1,100,679  
     Option Exercises and Stock Vested Table
          The Named Executive Officers did not exercise any unit options during 2007. In addition, the Named Executive Officers did not vest in any equity-based awards during the year.
Director Compensation
          The following table presents information regarding compensation paid to the independent directors of our general partner for the year ended December 31, 2007.
                                         
    Fees Earned                   All    
    or Paid   Unit   Option   Other    
    in Cash   Awards   Awards   Compensation   Total
               Name   ($)   ($) (1)   ($) (2)   ($) (5)   ($)
 
E. William Barnett
  $ 77,500     $ 68,562     $ 32,948  (3)   $ 3,933     $ 182,943  
Rex C. Ross
    62,500       19,575       34,530  (4)     890       117,496  
Charles M. Rampacek
    62,500       19,575       34,530  (4)     890       117,496  
 
(1)   In November 2007, each of the restricted unit grants made to our independent directors was amended to provide that the restricted units subject to such grants would immediately vest. The amounts presented for each director represent the expense recognized by us related to such restricted units during the year ended December 31, 2007. The number of restricted units that vested for each independent director was as follows: Mr. Barnett, 2,154; Mr. Ross, 615; and Mr. Rampacek, 615.
 
(2)   Amounts presented reflect the compensation expense recognized by EPGP related to unit appreciation rights (“UARs”) granted in 2006 under letter agreements. The UARs are accounted for as liability awards under SFAS 123(R) since they will be settled with cash.
 
(3)   At December 31, 2007, the fair value of UARs granted to Mr. Barnett was $96 thousand.
 
(4)   At December 31, 2007, the fair value of UARs granted to each of Mr. Ross and Mr. Rampacek was $102 thousand.
 
(5)   Amounts primarily represent the quarterly cash distributions each independent director received from restricted unit awards prior to the vesting of such awards in November 2007.
          Neither we nor EPGP provide any additional compensation to employees of EPCO who serve as directors of EPGP. The employees of EPCO who served as directors of EPGP during 2007 were Messrs. Duncan, Creel, Fowler, Bachmann, Cunningham and Phillips.

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          Currently, EPGP’s three independent directors, Messrs. Barnett, Ross and Rampacek, are provided cash compensation for their services as follows:
  §   Each independent director receives $75,000 in cash annually. Prior to August 2007, the annual retainer was $50,000 in cash and $25,000 worth of restricted units.
 
  §   If the individual serves as chairman of a committee of the Board of Directors, then he receives an additional $15,000 in cash annually.
          The independent directors of our general partner have also received unit-based compensation in the form of UARs. These awards consist of letter agreements with each of the independent directors and are not part of any established long-term incentive plan of the EPCO group of companies. The awards are based upon an incentive plan of EPE Holdings, and are made in the form of UAR grants for non-employee directors. The compensation expense associated with these awards is recognized by EPGP. These UARs entitle the directors to receive a cash amount in the future equal to the excess, if any, of the fair market value of Enterprise GP Holdings’ units (determined as of a future vesting date) over the grant date price of such units. If a director resigns prior to vesting, his UAR awards are forfeited.
          In August 2006, Mr. Barnett was granted 10,000 UARs under the letter agreement format. The grant date price of these rights was $35.71 per unit. These awards vest in August 2011 or on the date of certain qualifying events (as set forth in the form of grant). At December 31, 2007, the total fair value of these 10,000 UARs was $28 thousand, which was based on the following assumptions: (i) remaining life of award of four years; (ii) risk-free interest rate of 3.6%; (iii) an expected distribution yield on Enterprise GP Holdings’ units of 4.4%; and (iv) an expected unit price volatility of Enterprise GP Holdings’ units of 16.9%.
          In November 2006, Mr. Barnett was issued an additional 20,000 UARs and Mr. Ross and Mr. Rampacek were each granted 30,000 UARs under the letter agreement format. The grant date price of these UARs was $34.10 per unit. These awards vest in November 2011 or on the date of certain qualifying events (as set forth in the form of grant). At December 31, 2007, the total fair value of these 80,000 UARs was $272 thousand, which was based on the following assumptions: (i) remaining life of award of four years; (ii) risk-free interest rate of 3.6%; (iii) an expected distribution yield on Enterprise GP Holdings’ units of 4.4%; and (iv) an expected unit price volatility of Enterprise GP Holdings’ units of 16.9%.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
Security Ownership of Certain Beneficial Owners
          The following table sets forth certain information as of February 1, 2008, regarding each person known by our general partner to beneficially own more than 5% of our common units.
                         
            Amount and    
            Nature of    
Title of   Name and Address   Beneficial   Percent
Class   of Beneficial Owner   Ownership   of Class
 
Common units  
Dan L. Duncan
     (1)     %
       
1100 Louisiana Street, 10th Floor
Houston, Texas 77002
               
 
(1)   For a detailed listing of ownership amounts that comprise Mr. Duncan’s total beneficial ownership of our common units, see the table presented in the following section, “Security Ownership of Management,” within this Item 12.

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Security Ownership of Management
     Enterprise Products Partners L.P. and Enterprise GP Holdings L.P.
          The following table sets forth certain information regarding the beneficial ownership of our common units and the units of Enterprise GP Holdings L.P. as of February 1, 2008 by:
  §   our Named Executive Officers;
 
  §   the current Directors of EPGP; and
 
  §   the current directors and executive officers of EPGP as a group.
          If an individual does not own any securities in the foregoing registrants, he is not listed in the following table.
          Enterprise GP Holdings owns 100% of the membership interests of EPGP. All information with respect to beneficial ownership has been furnished by the respective directors or officers. Each person has sole voting and dispositive power over the securities shown unless otherwise indicated below. The beneficial ownership amounts of certain individuals include options to acquire our common units that are exercisable within 60 days of the filing date of this annual report.
          Mr. Duncan owns 50.4% of the voting stock of EPCO and, accordingly, exercises sole voting and dispositive power with respect to our common units beneficially owned by EPCO and its affiliates. The remaining shares of EPCO capital stock are owned primarily by trusts for the benefit of members of Mr. Duncan’s family. The address of EPCO is 1100 Louisiana Street, 10th Floor, Houston, Texas 77002.
                                 
    Limited Partner Ownership Interests In  
    Enterprise Products Partners L.P.     Enterprise GP Holdings L.P.  
    Amount and             Amount and        
    Nature Of             Nature Of        
Name of   Beneficial     Percent of     Beneficial     Percent of  
Beneficial Owner   Ownership     Class     Ownership     Class  
 
Dan L. Duncan:
                               
Units owned by EPCO:
                               
Through DFI Delaware Holdings, L.P.
    120,086,279       27.6 %            
Through Duncan Family Interests, Inc.
                69,203,487       56.2 %
Through Enterprise GP Holdings L.P.
    13,454,498       3.1 %            
Through DFI GP Holdings L.P.
                11,819,722       9.6 %
Units owned by DD Securities LLC
    487,100       *       3,745,673       3.0 %
Units owned by Employee Partnerships (1)
                6,283,479       5.1 %
Units owned by family trusts (2)
    13,008,241       3.0 %     243,071       *  
Units owned directly
    949,927       *              
     
Total for Dan L. Duncan
    147,986,045       34.0 %     91,295,432       74.1 %
Richard H. Bachmann (3)
    146,014       *       17,469       *  
Michael A. Creel (3)
    141,328       *       35,000       *  
Dr. Ralph S. Cunningham (3)
    45,106       *       4,000       *  
W. Randall Fowler (3)
    77,061       *       3,000       *  
James H. Lytal (3)
    103,325       *       5,000       *  
A.J. Teague (3)
    193,941       *       17,000       *  
E. William Barnett
    2,154       *              
Rex C. Ross
    24,285       *       5,400       *  
Charles M. Rampacek
    615       *              
All current directors and executive officers of EPGP, as a group, (14 individuals in total) (4)
    148,775,005       34.2 %     91,422,501       74.2 %
 
                               
*   The beneficial ownership of each individual is less than 1% of the registrant’s common units outstanding.
 
(1)   As a result of EPCO’s ownership of the general partners of the Employee Partnerships, Mr. Duncan is deemed beneficial owner of the securities held by these entities.
 
(2)   Mr. Duncan is deemed beneficial owner of the securities held by certain family trusts, the beneficiaries of which are shareholders of EPCO.
 
(3)   These individuals are Named Executive Officers.
 
(4)   Cumulatively, this group’s beneficial ownership amount includes 150,000 options to acquire common units of Enterprise Products Partners L.P. that were issued under the 1998 Plan. These options are exercisable within 60 days of the filing date of this report.

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          Essentially all of the ownership interests in us and Enterprise GP Holdings that are owned or controlled by EPCO are pledged as security under the credit facility of an EPCO affiliate. This credit facility contains customary and other events of default relating to EPCO and certain of its affiliates, including Enterprise GP Holdings, TEPPCO and us. In the event of a default under this credit facility, a change in control of Enterprise GP Holdings or us could occur, including a change in control of our respective general partners.
     Duncan Energy Partners L.P.
          On February 5, 2007, Duncan Energy Partners, a consolidated subsidiary of ours, completed its initial public offering of 14,950,000 common units. Certain of our directors and executive officers purchased common units of Duncan Energy Partners in this offering. The following table presents the beneficial ownership of common units of Duncan Energy Partners by our directors, Named Executive Officers and all directors and officers of our general partner (as a group) at February 1, 2008.
                 
    Duncan Energy Partners  
    Amount        
    And Nature Of        
Name of   Beneficial     Percent of  
Beneficial Owner   Ownership     Class  
Dan L. Duncan:
               
Through EPO (1)
    5,351,571       26.4 %
Units owned by family trusts
    103,100       *  
 
   
Total for Dan L. Duncan
    5,454,671       26.9 %
Richard H. Bachmann (2,3)
    10,172       *  
Michael A. Creel (3)
    7,500       *  
Dr. Ralph S. Cunningham (3)
    3,000       *  
W. Randall Fowler (3,4)
    2,000       *  
Rex C. Ross
    5,000       *  
All current directors and executive officers of EPGP, as a group (14 individuals in total)
    5,494,943       27.1 %
     
*   The beneficial ownership of each individual is less than 1% of the registrant’s units outstanding.
 
(1)   The number of common units shown for Dan L. Duncan represents the final amount of common units issued to EPO in connection with its contribution of equity interests to Duncan Energy Partners in February 2007.
 
(2)   Mr. Bachmann is the Chief Executive Officer of Duncan Energy Partners.
 
(3)   These individuals are Named Executive Officers.
 
(4)   Mr. Fowler is the Chief Financial Officer of Duncan Energy Partners.

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Securities Authorized for Issuance Under Equity Compensation Plans
          The following table sets forth certain information as of December 31, 2007 regarding the 1998 Plan, under which our common units are authorized for issuance to EPCO’s key employees and to directors of EPGP through the exercise of unit options.
                         
                    Number of
                    units
                    remaining
                    available for
    Number of           future issuance
    units to   Weighted-   under equity
    be issued   average   compensation
    upon exercise   exercise price   plans (excluding
    of outstanding   of outstanding   securities
    common unit   common unit   reflected in
Plan Category   options   options   column (a)
 
    (a)   (b)   (c)
Equity compensation plans approved by unitholders:
                       
1998 Plan
    2,315,000     $ 26.18       1,282,256  
Equity compensation plans not approved by unitholders:
                       
None.
                 
         
Total for equity compensation plans
    2,315,000     $ 26.18       1,232,256  
         
 
(1)   Of the 2,315,000 unit options outstanding at December 31, 2007, 335,000 were immediately exercisable and an additional 285,000, 380,000, 510,000 and 805,000 options are exercisable in 2008, 2009, 2010 and 2011, respectively.
     1998 Plan
          The 1998 Plan is effective until either all available common units under the plan have been issued to participants or the earlier termination of the 1998 Plan by EPCO. The 1998 Plan also provides for the issuance of restricted common units, of which 1,688,540 were outstanding at December 31, 2007. During 2007, a total of 738,040 restricted unit awards were issued to key employees of EPCO and our independent directors. For additional information regarding the 1998 Plan, see Note 5 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
     Enterprise Products 2008 Long-Term Incentive Plan
          On January 29, 2008, the unitholders of Enterprise Products Partners approved the Enterprise Products 2008 Long-Term Incentive Plan (the “Incentive Plan”), which provides for awards of the Partnership’s common units and other rights to the Partnership’s non-employee directors and to consultants and employees of EPCO and its affiliates providing services to the Partnership. Awards under the Incentive Plan may be granted in the form of restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The Incentive Plan will be administered by EPGP’s ACG Committee. Up to 10,000,000 of the Partnership’s common units may be granted as awards under the Incentive Plan, with such amount subject to adjustment as provided for under the terms of the plan.
          The exercise price of unit options or UARs awarded to participants will be determined by the ACG Committee (at its discretion) at the date of grant and may be no less than the fair market value of the option award as of the date of grant. The Incentive Plan may be amended or terminated at any time by the Board of Directors of EPCO or EPGP’s ACG Committee; however, any material amendment, such as a significant increase in the number of units available under the plan or a change in the types of awards available under the plan, would require the approval of the unitholders of the Partnership. The ACG Committee is also authorized to make adjustments in the terms and conditions of, and the criteria included in awards under the plan in specified circumstances. The Incentive Plan is effective until January 29, 2018 or, if earlier, the time which all available units under the Incentive Plan have been delivered to participants or the time of termination of the plan by EPCO or EPGP’s ACG Committee.

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Item 13. Certain Relationships and Related Transactions, and Director Independence.
Certain Relationships and Related Transactions
          The following information summarizes our business relationships and transactions with related parties during the year ended December 31, 2007. We believe that the terms and provisions of our related party agreements are fair to us; however, such agreements and transactions may not be as favorable to us as we could have obtained from unaffiliated third parties. For additional information regarding our related party transactions, see Note 17 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
     Relationship with EPCO and affiliates
          We have an extensive and ongoing relationship with EPCO and its affiliates, which include the following significant entities that are not a part of our consolidated group of companies:
  §   EPCO and its private company subsidiaries;
 
  §   EPGP, our sole general partner;
 
  §   Enterprise GP Holdings, which owns and controls our general partner;
 
  §   the Employee Partnerships;
 
  §   TEPPCO, which is owned and controlled by Enterprise GP Holdings; and
 
  §   Energy Transfer Equity, an equity method investment of Enterprise GP Holdings.
          We also have an ongoing relationship with Duncan Energy Partners, the financial statements of which are consolidated with those of our own. Our transactions with Duncan Energy Partners are eliminated in consolidation.
          EPCO is a private company controlled by Dan L. Duncan, who is also a Director and Chairman of EPGP, our general partner. At December 31, 2007, EPCO and its affiliates beneficially owned 147,986,045 (or 34.0%) of our outstanding common units, which includes 13,454,498 of our common units owned by Enterprise GP Holdings. In addition, at December 31, 2007, EPCO and its affiliates beneficially owned 77.1% of the limited partner interests of Enterprise GP Holdings and 100% of its general partner, EPE Holdings. Enterprise GP Holdings owns all of the membership interests of EPGP. The principal business activity of EPGP is to act as our managing partner. The executive officers and certain of the directors of EPGP and EPE Holdings are employees of EPCO.
          As our general partner, EPGP received cash distributions of $124.4 million from us during the year ended December 31, 2007. This amount includes incentive distributions of $107.4 million.
          We and EPGP are both separate legal entities apart from each other and apart from EPCO, Enterprise GP Holdings and their respective other affiliates, with assets and liabilities that are separate from those of EPCO, Enterprise GP Holdings and their respective other affiliates. EPCO and its private company subsidiaries and affiliates depend on the cash distributions they receive from us, Enterprise GP Holdings and other investments to fund their other operations and to meet their debt obligations. EPCO and its private company affiliates received $355.5 million in cash distributions from us and Enterprise GP Holdings during the year ended December 31, 2007.
          The ownership interests in us that are owned or controlled by Enterprise GP Holdings are pledged as security under its credit facility. In addition, substantially all of the ownership interests in us that are owned or controlled by EPCO and its affiliates, other than those interests owned by Enterprise GP Holdings, Dan Duncan LLC and certain trusts affiliated with Dan L. Duncan, are pledged as security under

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the credit facility of a private company affiliate of EPCO. This credit facility contains customary and other events of default relating to EPCO and certain affiliates, including Enterprise GP Holdings, TEPPCO and us.
          An affiliate of EPCO provides us trucking services for the transportation of NGLs and other products. For the year ended December 31, 2007, we paid this trucking affiliate $17.5 million for such services.
          We lease office space in various buildings from affiliates of EPCO. The rental rates in these lease agreements approximate market rates. For the year ended December 31, 2007, we paid EPCO $5.6 million for office space leases.
          EPCO Administrative Services Agreement. We have no employees. All of our operating functions and general and administrative support services are provided by employees of EPCO pursuant to an administrative services agreement (the “ASA”). We, Duncan Energy Partners, Enterprise GP Holdings, TEPPCO and our respective general partners are parties to the ASA. The significant terms of the ASA are as follows:
  §   EPCO will provide selling, general and administrative services, and management and operating services, as may be necessary to manage and operate our businesses, properties and assets (all in accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services.
 
  §   We are required to reimburse EPCO for its services in an amount equal to the sum of all costs and expenses incurred by EPCO which are directly or indirectly related to our business or activities (including expenses reasonably allocated to us by EPCO). In addition, we have agreed to pay all sales, use, excise, value added or similar taxes, if any, that may be applicable from time to time in respect of the services provided to us by EPCO.
 
  §   EPCO will allow us to participate as named insureds in its overall insurance program, with the associated premiums and other costs being allocated to us.
          Under the ASA, EPCO subleases to us (for $1 per year) certain equipment which it holds pursuant to operating leases and has assigned to us its purchase option under such leases (the “retained leases”). EPCO remains liable for the actual cash lease payments associated with these agreements. We record the full value of these payments made by EPCO on our behalf as a non-cash related party operating lease expense, with the offset to partners’ equity accounted for as a general contribution to our partnership. At December 31, 2007, the retained leases were for a cogeneration unit and approximately 100 railcars. Should we decide to exercise the purchase options associated with the retained leases, $2.3 million would be payable in 2008 and $3.1 million in 2016.
          Our operating costs and expenses for the year ended December 31, 2007 include reimbursement payments to EPCO for the costs it incurs to operate our facilities, including compensation of employees. We reimburse EPCO for actual direct and indirect expenses it incurs related to the operation of our assets. Such reimbursements were $273.0 million during the year ended December 31, 2007.
          Likewise, our general and administrative costs for the year ended December 31, 2007 includes amounts we reimburse to EPCO for administrative services, including compensation of employees. In general, our reimbursement to EPCO for administrative services is either (i) on an actual basis for direct expenses it may incur on our behalf (e.g., the purchase of office supplies) or (ii) based on an allocation of such charges between the various parties to ASA based on the estimated use of such services by each party (e.g., the allocation of general legal or accounting salaries based on estimates of time spent on each entity’s business and affairs). Such reimbursements were $56.5 million during the year ended December 31, 2007.

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          The ASA also addresses potential conflicts that may arise among Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), and the EPCO Group. The EPCO Group includes EPCO and its other affiliates, but excludes Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners and their respective general partners. With respect to potential conflicts, the ASA provides, among other things, that:
  §   If a business opportunity to acquire “equity securities” (as defined below) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), Duncan Energy Partners (including DEP GP), then Enterprise GP Holdings will have the first right to pursue such opportunity. The term “equity securities” is defined to include:
  §   general partner interests (or securities which have characteristics similar to general partner interests) or interests in “persons” that own or control such general partner or similar interests (collectively, “GP Interests”) and securities convertible, exercisable, exchangeable or otherwise representing ownership or control of such GP Interests; and
 
  §   incentive distribution rights and limited partner interests (or securities which have characteristics similar to incentive distribution rights or limited partner interests) in publicly traded partnerships or interests in “persons” that own or control such limited partner or similar interests (collectively, “non-GP Interests”); provided that such non-GP Interests are associated with GP Interests and are owned by the owners of GP Interests or their respective affiliates.
      Enterprise GP Holdings will be presumed to want to acquire the equity securities until such time as EPE Holdings advises the EPCO Group, EPGP and DEP GP that it has abandoned the pursuit of such business opportunity. In the event that the purchase price of the equity securities is reasonably likely to equal or exceed $100 million, the decision to decline the acquisition will be made by the Chief Executive Officer of EPE Holdings after consultation with and subject to the approval of the ACG Committee of EPE Holdings. If the purchase price is reasonably likely to be less than $100 million, the Chief Executive Officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings.
 
      In the event that Enterprise GP Holdings abandons the acquisition and so notifies the EPCO Group, EPGP and DEP GP, Enterprise Products Partners will have the second right to pursue such acquisition. Enterprise Products Partners will be presumed to want to acquire the equity securities until such time as EPGP advises the EPCO Group and DEP GP that Enterprise Products Partners has abandoned the pursuit of such acquisition. In determining whether or not to pursue the acquisition, Enterprise Products Partners will follow the same procedures applicable to Enterprise GP Holdings, as described above but utilizing EPGP’s Chief Executive Officer and ACG Committee.
 
      In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition.
 
      In the event Enterprise Products Partners abandons the acquisition opportunity for the equity securities and so notifies the EPCO Group and DEP GP, the EPCO Group may pursue the acquisition or offer the opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates, in either case, without any further obligation to any other party or offer such opportunity to other affiliates.
 
  §   If any business opportunity not covered by the preceding bullet point (i.e. not involving “equity securities”) is presented to the EPCO Group, Enterprise Products Partners (including EPGP), Enterprise GP Holdings (including EPE Holdings), or Duncan Energy Partners (including DEP GP), Enterprise Products Partners will have the first right to pursue such opportunity either for itself or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan

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      Energy Partners. It will be presumed that Enterprise Products Partners will pursue the business opportunity until such time as its general partner advises the EPCO Group, EPE Holdings and DEP GP that it has abandoned the pursuit of such business opportunity.
 
      In the event the purchase price or cost associated with the business opportunity is reasonably likely to equal or exceed $100 million, any decision to decline the business opportunity will be made by the Chief Executive Officer of EPGP after consultation with and subject to the approval of the ACG Committee of EPGP. If the purchase price or cost is reasonably likely to be less than $100 million, the Chief Executive Officer of EPGP may make the determination to decline the business opportunity without consulting EPGP’s ACG Committee.
 
      In its sole discretion, Enterprise Products Partners may affirmatively direct such acquisition opportunity to Duncan Energy Partners. In the event this occurs, Duncan Energy Partners may pursue such acquisition.
 
      In the event that Enterprise Products Partners abandons the business opportunity for itself and Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings and DEP GP, Enterprise GP Holdings will have the second right to pursue such business opportunity. It will be presumed that Enterprise GP Holdings will pursue such acquisition until such time as its general partner declines such opportunity (in accordance with the procedures described above for Enterprise Products Partners) and advises the EPCO Group that it has abandoned the pursuit of such business opportunity. Should this occur, the EPCO Group may either pursue the business opportunity or offer the business opportunity to TEPPCO (including TEPPCO GP) and their controlled affiliates without any further obligation to any other party or offer such opportunity to other affiliates.
          None of Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or their respective general partners or the EPCO Group have any obligation to present business opportunities to TEPPCO (including TEPPCO GP) or their controlled affiliates. Likewise, TEPPCO (including TEPPCO GP) and their controlled affiliates have no obligation to present business opportunities to Enterprise Products Partners, Enterprise GP Holdings, Duncan Energy Partners or their respective general partners or the EPCO Group.
          Employee Partnerships. EPCO formed the Employee Partnerships to serve as an incentive arrangement for key employees of EPCO by providing them a “profits interest” in such partnerships. Certain EPCO employees who work on behalf of us and EPCO were issued Class B limited partner interests and admitted as Class B limited partners without any capital contribution. The profits interest awards (i.e., the Class B limited partner interests) in the Employee Partnerships entitles each holder to participate in the appreciation in value of the Parent Company’s Units. For information regarding the Employee Partnerships, see Note 5 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.
     Relationship with TEPPCO
          TEPPCO became a related party to us in February 2005 in connection with the acquisition of TEPPCO GP by a private company subsidiary of EPCO. In May 2007, Enterprise GP Holdings purchased TEPPCO GP from this private company subsidiary of EPCO.
          We received $67.6 million from TEPPCO during the year ended December 31, 2007 from the sale of hydrocarbon products. We paid TEPPCO $19.4 million for NGL pipeline transportation and storage services during the year ended December 31, 2007.
          In August 2006, we became a joint venture partner with TEPPCO in its Jonah Gas Gathering Company (“Jonah”), which owns the Jonah Gas Gathering System located in the Greater Green River Basin of southwestern Wyoming. The Jonah Gathering System gathers and transports natural gas produced from the Jonah and Pinedale fields to regional natural gas processing plants and major interstate pipelines that deliver natural gas to end-user markets.

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          Prior to entering into the Jonah joint venture, we managed the construction of the Phase V expansion and funded the initial construction costs under a letter of intent we entered into in February 2006. In connection with the joint venture arrangement, we and TEPPCO plan to continue the Phase V expansion, which is expected to increase the capacity of the Jonah Gathering System from 1.5 Bcf/d to 2.4 Bcf/d and to significantly reduce system operating pressures, which we anticipate will lead to increased production rates and ultimate reserve recoveries. The first portion of the expansion, which has increased the system gathering capacity to 2.0 Bcf/d, was completed in July 2007 and the final phase of this expansion is expected to be completed by April 2008. The total anticipated cost of the Phase V expansion is expected to be approximately $505.0 million. We continue to manage the Phase V construction project.
          Since August 1, 2006, we and TEPPCO have equally shared in the construction costs of the Phase V expansion. TEPPCO has reimbursed us $261.6 million, which represents 50% of total Phase V costs incurred through December 31, 2007. We had a receivable of $9.9 million from TEPPCO at December 31, 2007 for Phase V expansion costs.
          TEPPCO was entitled to all distributions from the joint venture until specified milestones were achieved, at which point, we became entitled to receive 50% of the incremental cash flow from portions of the system placed in service as part of the expansion. Since the first phase of this expansion was reached in July 2007, we and TEPPCO have shared earnings based on a formula that takes into account our respective capital contributions, including expenditures by TEPPCO prior to the expansion.
          At December 31, 2007, we owned an approximate 19.4% interest in Jonah and TEPPCO owns 80.6%. We operate the Jonah system. We account for our investment in the Jonah joint venture using the equity method.
          The Jonah joint venture is governed by a management committee comprised of two representatives approved by us and two appointed by TEPPCO, each with equal voting power. After an in-depth consideration of all relevant factors, this transaction was approved by the ACG Committee of our general partner and the Audit and Conflicts Committee of the general partner of TEPPCO. The ACG Committee of our general partner received a fairness opinion in connection with this transaction. The transaction was reviewed and recommended for approval by the Audit and Conflicts Committee of TEPPCO GP with assistance from an independent financial advisor.
          We have agreed to indemnify TEPPCO from any and all losses, claims, demands, suits, liabilities, costs and expenses arising out of or related to breaches of our representations, warranties, or covenants related to the Jonah joint venture. A claim for indemnification cannot be filed until the losses suffered by TEPPCO exceed $1.0 million. The maximum potential amount of future payments under the indemnity agreement is limited to $100.0 million. All indemnity payments are net of insurance recoveries that TEPPCO may receive from third-party insurance carriers. We carry insurance coverage that may offset any payments required under the indemnification.
          In January 2007, we purchased a 10-mile segment of pipeline from TEPPCO located in the Houston area for $8.0 million. This pipeline segment is part of the DEP South Texas NGL Pipeline System that commenced operations in January 2007. In addition, we entered into a lease with TEPPCO for an 11-mile interconnecting pipeline located in the Houston area that is part of the DEP South Texas NGL Pipeline System. Although the primary term of the lease expired in September 2007, it is being renewed on a month-to-month basis until construction of a parallel pipeline is completed in early 2008. These transactions were in accordance with the Board-approved management authorization policy.
     Relationship with Energy Transfer Equity
          Enterprise GP Holdings acquired equity method investments in Energy Transfer Equity and its general partner in May 2007. As a result, Energy Transfer Equity and its consolidated subsidiaries became related parties to our consolidated businesses.

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          For the eight months ended December 31, 2007, we recorded $294.4 million of revenues from Energy Transfer Partners, L.P. (“ETP”), primarily from NGL marketing activities. We incurred $35.2 million in operating costs and expenses for the eight months ended December 31, 2007. We have a long-term revenue generating contract with Titan Energy Partners, L.P. (“Titan”), a consolidated subsidiary of ETP. Titan purchases substantially all of its propane requirements from us. The contract continues until March 31, 2010 and contains renewal and extension options. We and Energy Transfer Company (“ETC OLP”) transport natural gas on each other’s systems and share operating expenses on certain pipelines. ETC OLP also sells natural gas to us.
Relationships with Unconsolidated Affiliates
          Many of our unconsolidated affiliates perform supporting or complementary roles to our other business operations. Since we and our affiliates hold ownership interests in these entities and directly or indirectly benefit from our related party transactions with such entities, they are presented here. The following information summarizes significant related party transactions with our current unconsolidated affiliates:
  §   We sell natural gas to Evangeline, which, in turn, uses the natural gas to satisfy supply commitments it has with a major Louisiana utility. Revenues from Evangeline were $268.0 million for the year ended December 31, 2007. In addition, we furnished $1.1 million in letters of credit on behalf of Evangeline at December 31, 2007.
 
  §   We pay Promix for the transportation, storage and fractionation of NGLs. In addition, we sell natural gas to Promix for its plant fuel requirements. For the year ended December 31, 2007, we recorded revenues of $17.3 million from Promix and paid Promix $30.4 million for its services to us.
 
  §   We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $9.3 million for such services during the year ended December 31, 2007.
Relationship with Duncan Energy Partners
          In September 2006, we formed a consolidated subsidiary, Duncan Energy Partners, to acquire, own and operate a diversified portfolio of midstream energy assets and to support the growth objectives of EPO. On February 5, 2007, this subsidiary completed its initial public offering of 14,950,000 common units at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of $291.9 million. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of these net proceeds to Enterprise Products Partners (along with $198.9 million in borrowings under its credit facility and a final amount of 5,351,571 common units of Duncan Energy Partners). Duncan Energy Partners used $38.5 million of net proceeds from the overallotment to redeem 1,950,000 of the 7,301,571 common units it had originally issued to Enterprise Products Partners, resulting in the final amount of 5,351,571 common units beneficially owned by Enterprise Products Partners. We used the cash received from Duncan Energy Partners to temporarily reduce amounts outstanding under EPO’s Multi-Year Revolving Credit Facility.
          In addition to the 34% direct ownership interest we retained in certain subsidiaries of Duncan Energy Partners, we also own the 2% general partner interest in Duncan Energy Partners and 26.4% of Duncan Energy Partners’ outstanding common units. EPO directs the business operations of Duncan Energy Partners through its control of Duncan Holdings, LLC (“DEP GP”). Certain of our officers and directors are also beneficial owners of common units of Duncan Energy Partners (see Item 12).
          For financial reporting purposes, we consolidate the financial statements of Duncan Energy Partners with those of our own and reflect its operations in our business segments. All intercompany transactions between us and Duncan Energy Partners are eliminated in the preparation of our consolidated financial statements. Also, due to common control of the entities by Dan L. Duncan, the initial consolidated balance sheet of Duncan Energy Partners reflects our historical carrying basis in each of the

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subsidiaries contributed to Duncan Energy Partners. Public ownership of Duncan Energy Partners’ net assets and earnings are presented as a component of minority interest in our consolidated financial statements.
          The borrowings of Duncan Energy Partners are presented as part of our consolidated debt; however, we do not have any obligation for the payment of interest or repayment of borrowings incurred by Duncan Energy Partners.
          We have significant involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions: (i) we utilize storage services provided by Mont Belvieu Caverns to support our Mont Belvieu fractionation and other businesses; (ii) we buy natural gas from and sell natural gas to Acadian Gas in connection with our normal business activities; and (iii) we are the sole shipper on the DEP South Texas NGL Pipeline System.
          We may contribute other equity interests in our subsidiaries to Duncan Energy Partners in the near term and use the proceeds we receive from Duncan Energy Partners to fund our capital spending program.
          For additional information regarding Duncan Energy Partners, see “Other Items — Initial Public Offering of Duncan Energy Partners” under Item 7 of this annual report.
          Omnibus Agreement. On February 5, 2007, EPO and Duncan Energy Partners entered into an Omnibus Agreement that governs our relationship with Duncan Energy Partners on the following matters:
  §   indemnification for certain environmental liabilities, tax liabilities and right-of-way defects;
 
  §   reimbursement of certain expenditures incurred by DEP South Texas NGL and Mont Belvieu Caverns;
 
  §   a right of first refusal to EPO in Duncan Energy Partners’ current and future subsidiaries and a right of first refusal on the material assets of these entities, other than sales of inventory and other assets in the ordinary course of business; and
 
  §   a preemptive right with respect to equity securities issued by certain of Duncan Energy Partners’ subsidiaries, other than as consideration in an acquisition or in connection with a loan or debt financing.
          EPO has indemnified Duncan Energy Partners against certain pre-February 2007 environmental and related liabilities associated with the assets EPO contributed to Duncan Energy Partners at the time of its initial public offering. These liabilities include both known and unknown environmental and related liabilities. This indemnification obligation will terminate on February 5, 2010. There is an aggregate cap of $15.0 million on the amount of indemnity coverage. In addition, Duncan Energy Partners is not entitled to indemnification until the aggregate amount of claims it incurs exceeds $250 thousand. Liabilities resulting from a change of law after February 5, 2007 are excluded from the EPO environmental indemnity. In addition, EPO has indemnified Duncan Energy Partners for liabilities related to:
  §   certain defects in the easement rights or fee ownership interests in and to the lands on which any assets contributed to Duncan Energy Partners in connection with its initial public offering are located and failure to obtain certain consents and permits necessary to conduct its business that arise through February 5, 2010; and
 
  §   certain income tax liabilities attributable to the operation of the assets contributed to Duncan Energy Partners in connection with its initial public offering prior to February 5, 2007.
          The Omnibus Agreement may not be amended without the prior approval of the ACG Committee if the proposed amendment will, in the reasonable discretion of DEP GP, adversely affect holders of the it’s common units.

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          Neither we, nor EPO and any of its affiliates are restricted under the Omnibus Agreement from competing with Duncan Energy Partners. Except as otherwise expressly agreed in the EPCO administrative services agreement, EPO and any of its affiliates may acquire, construct or dispose of additional midstream energy or other assets in the future without any obligation to offer Duncan Energy Partners the opportunity to purchase or construct those assets. These agreements are in addition to other agreements relating to business opportunities and potential conflicts of interest set forth in the administrative services agreement with EPO, EPCO and other affiliates of EPCO.
          Under the Omnibus Agreement, EPO agreed to make additional contributions to Duncan Energy Partners as reimbursement for its 66% share of any excess construction costs above (i) the $28.6 million of estimated capital expenditures to complete the Phase II expansions of the DEP South Texas NGL Pipeline System and (ii) $14.1 million of estimated construction costs for additional brine production capacity and above-ground storage reservoir projects at Mont Belvieu, Texas. Both projects were underway at the time of Duncan Energy Partners’ initial public offering. In December 2007, EPO made contributions totaling $9.9 million to Duncan Energy Partners’ subsidiaries in connection with this provision of the Omnibus Agreement.
Review and Approval of Transactions with Related Parties
          Our partnership agreement and ACG Committee charter set forth policies and procedures for the review and approval of certain transactions with persons affiliated with or related to us. As further described below, our partnership agreement and ACG Committee charter set forth procedures by which related party transactions and conflicts of interest may be approved or resolved by our general partner or the ACG Committee. Under our partnership agreement, whenever a potential conflict of interest exists or arises between our general partner or any of its affiliates, on the one hand, and us, any of our subsidiaries or any partner, on the other hand, any resolution or course of action by our general partner or its affiliates in respect of such conflict of interest is permitted and deemed approved by all of our partners, and will not constitute a breach of our partnership agreement or any agreement contemplated by such agreement, or of any duty stated or implied by law or equity, if the resolution or course of action is or, by operation of the partnership agreement is deemed to be, fair and reasonable to us; provided that, any conflict of interest and any resolution of such conflict of interest will be conclusively deemed fair and reasonable to us if such conflict of interest or resolution is (i) approved by a majority of the members of our ACG Committee (“Special Approval”), or (ii) on terms objectively demonstrable to be no less favorable to us than those generally being provided to or available from unrelated third parties.
          The ACG Committee (in connection with Special Approval) is authorized in connection with its resolution of any conflict of interest to consider:
  §   the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;
 
  §   the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership);
 
  §   any customary or accepted industry practices and any customary or historical dealings with a particular person;
 
  §   any applicable generally accepted accounting or engineering practices or principles;
 
  §   the relative cost of capital of the parties and the consequent rates of return to the equity holders of the parties; and
 
  §   such additional factors as the committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

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          The review and approval process of the ACG Committee, including factual matters that may be considered in determining whether a transaction is fair and reasonable, is generally governed by Section 7.9 of our partnership agreement. As discussed above, the ACG Committee’s Special Approval is conclusively deemed fair and reasonable to us under the partnership agreement.
          Related party transactions that do not occur under the ASA and that are not reviewed by the ACG Committee, as described above, may be subject to our general partner’s Board-approved written internal review and approval policies and procedures. These internal policies and procedures, which apply to related party transactions as well as transactions with unrelated parties, specify thresholds for our general partner’s officers and managers to authorize various categories of transactions, including purchases and sales of assets, expenditures, commercial and financial transactions and legal agreements. The specified thresholds for some categories of transactions are less than $120,000 and for others are substantially greater.
          In submitting a matter to the ACG Committee, the Board or the general partner may charge the committee with reviewing the transaction and providing the Board a recommendation, or it may delegate to the committee the power to approve the matter. When so engaged, the ACG Committee Charter provides that, unless the ACG Committee determines otherwise, the committee shall perform the following functions:
  §   Review a summary of the proposed transaction(s) that outlines (i) its terms and conditions (explicit and implicit), (ii) a brief history of the transaction, and (iii) the impact that the transaction will have on our unitholders and personnel, including earnings per unit and distributable cash flow.
 
  §   Review due diligence findings by management and make additional due diligence requests, if deemed necessary.
 
  §   Engage third-party independent advisors, where necessary, to provide committee members with comparable market values, legal advice and similar services directly related to the proposed transaction.
 
  §   Conduct interviews regarding the proposed transaction with the most knowledgeable company officials to ensure that the committee members have all relevant facts before rendering their judgment.
          On November 6, 2007, the ACG Committee charter was amended and restated. The amended and restated charter provides, among other things, that the ACG Committee will review and approve related-party transactions (i) for which Board approval is required by the partnership’s management authorization policy (generally, for transactions involving amounts greater than $100 million), (ii) where an officer or director of our general partner or of any partnership subsidiary is a party, (iii) when requested to do so by management of the partnership or the Board, or (iv) pursuant to the limited partnership agreement of the partnership or the limited liability company agreement of our general partner.
          In the normal course of business, our management routinely reviews all other related party transactions, including proposed asset purchases and business combinations and purchases and sales of product. As a matter of course, management reviews the terms and conditions of the proposed transactions, performs appropriate levels of due diligence and assesses the impact of the transaction on our partnership. In addition, the ACG Committee reviews a summary of all related party transactions with management on a quarterly basis where the amounts involved exceed $1.0 million and the underlying prices are not market-based. In connection with such review, the ACG Committee received no indication that such transactions were not fair and reasonable to the Company or that management of the Company improperly exercised its authority under our general partner’s written internal review and approval policies and procedures.

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          The ACG Committee does not separately review individual transactions covered by our administrative services agreement with EPCO, which agreement and related allocation methods have been previously reviewed and approved by the ACG Committee and/or the Board. The administrative services agreement governs numerous day-to-day transactions between us and our subsidiaries and EPCO and its affiliates, including the provision by EPCO of administrative and other services to us and our subsidiaries and our reimbursement of costs for those services.
          During the year ended December 31, 2006, the ACG Committee reviewed and approved the purchase of the Pioneer plant from TEPPCO and Jonah Joint Venture with TEPPCO referenced elsewhere in this Item 13. All other transactions with related parties were either governed by the administrative services agreement or effected under our general partner’s written internal review and approval policies and procedures.
Director Independence
          Messrs. Barnett, Ross and Rampacek have been determined to be independent under the applicable NYSE listing standards and are independent under the rules of the SEC applicable to audit committees. For a discussion of independence standards applicable to the Board and factors considered by the Board in making its independence determinations, please refer to “Corporate Governance” and “ACG Committee” under Item 10 of this annual report.
Item 14. Principal Accountant Fees and Services.
          We have engaged Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte & Touche”) as our independent auditor. The following table summarizes fees we paid Deloitte & Touche for independent auditing, tax and related services for each of the last two fiscal years (dollars in thousands):
                 
    For Year Ended December 31,
    2007   2006
Audit Fees (1)
  $ 3,825     $ 4,476  
Audit-Related Fees (2)
    79       13  
Tax Fees (3)
    341       297  
All Other Fees (4)
    n/a       n/a  
 
(1)   Audit fees represent amounts billed for each of the years presented for professional services rendered in connection with (i) the audit of our annual financial statements and internal controls over financial reporting, (ii) the review of our quarterly financial statements or (iii) those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters. This information is presented as of the latest practicable date for this annual report.
 
(2)   Audit-related fees represent amounts we were billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews. This category primarily includes services relating to internal control assessments and accounting-related consulting.
 
(3)   Tax fees represent amounts we were billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning. This category primarily includes services relating to the preparation of unitholder annual K-1 statements and partnership tax planning.
 
(4)   All other fees represent amounts we were billed in each of the years presented for services not classifiable under the other categories listed in the table above. No such services were rendered by Deloitte & Touche during the last two years.
          The ACG Committee of our general partner has approved the use of Deloitte & Touche as our independent principal accountant. In connection with its oversight responsibilities, the ACG Committee has adopted a pre-approval policy regarding any services proposed to be performed by Deloitte & Touche. The pre-approval policy includes four primary service categories: Audit, Audit-related, Tax and Other.
          In general, as services are required, management and Deloitte & Touche submit a detailed proposal to the ACG Committee discussing the reasons for the request, the scope of work to be performed, and an estimate of the fee to be charged by Deloitte & Touche for such work. The ACG Committee

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discusses the request with management and Deloitte & Touche, and if the work is deemed necessary and appropriate for Deloitte & Touche to perform, approves the request subject to the fee amount presented (the initial “pre-approved” fee amount). As part of these discussions, the ACG Committee must determine whether or not the proposed services are permitted under the rules and regulations concerning auditor independence under the Sarbanes-Oxley Act of 2002 as well as rules of the American Institute of Certified Public Accountants. If at a later date, it appears that the initial pre-approved fee amount may be insufficient to complete the work, then management and Deloitte & Touche must present a request to the ACG Committee to increase the approved amount and the reasons for the increase.
          Under the pre-approval policy, management cannot act upon its own to authorize an expenditure for services outside of the pre-approved amounts. On a quarterly basis, the ACG Committee is provided a schedule showing Deloitte & Touche’s pre-approved amounts compared to actual fees billed for each of the primary service categories. The ACG Committee’s pre-approval process helps to ensure the independence of our principal accountant from management.
          In order for Deloitte & Touche to maintain its independence, we are prohibited from using them to perform general bookkeeping, management or human resource functions, and any other service not permitted by the Public Company Accounting Oversight Board. The ACG Committee’s pre-approval policy also precludes Deloitte & Touche from performing any of these services for us.
PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a)(1) Financial Statements
          Our consolidated financial statements are included under Part II, Item 8 of this annual report. For a listing of these statements and accompanying footnotes, see “Index to Financial Statements” under Item 8 of this annual report.
(a)(2) Financial Statement Schedules
          All schedules, have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
     
2.1
  Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
 
   
2.2
  Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
 
   
2.3
  Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
 
   
2.4
  Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to the Form 8-K filed April 21, 2004).

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2.5
  Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003). 
 
   
3.1
  Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 8, 2007).
 
   
3.2
  Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 10, 2005).
 
   
3.3
  First Amendment to Fifth Amended and Restated Partnership Agreement of Enterprise Products Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3, 2008).
 
   
3.4
  Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of November 7, 2007 (incorporated by reference to Exhibit 3.2 to Form 10-Q filed November 8, 2007).
 
   
3.5
  Limited Liability Company Agreement of Enterprise Products Operating LLC dated as of June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed on August 8, 2007).
 
   
3.6
  Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
 
   
3.7
  Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
 
   
3.8
  Certificate of Limited Partnership of Duncan Energy Partners L.P. (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P. Form S-1 Registration Statement, Reg. No. 333-138371, filed November 2, 2006).
 
   
3.9
  Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P., dated February 5, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K/A filed February 5, 2007).
 
   
3.10
  First Amendment to Amended and Restated Partnership Agreement of Duncan Energy Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K filed on January 3, 2008).
 
   
4.1
  Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998).
 
   
4.2
  Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).
 
   
4.3
  First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
 
   
4.4
  Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
 
   
4.5
  Third Supplemental Indenture dated as of June 30, 2007, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed on August 8, 2007) .
 
   
4.6
  Amended and Restated Revolving Credit Agreement dated as of November 19, 2007 among Enterprise Products Operating LLC, the financial institutions party thereto as lenders, Wachovia Bank, National Association, as Administrative Agent, Issuing Bank and Swingline Lender, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents, and SunTrust Bank, Mizuho Corporate Bank, Ltd. and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 20, 2007).

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4.7
  Amended and Restated Guaranty Agreement dated as of November 19, 2007 executed by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed on November 20, 2007).
 
   
4.8
  Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed on October 6, 2004).
 
   
4.9
  First Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on October 6, 2004).
 
   
4.10
  Second Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 6, 2004).
 
   
4.11
  Third Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed on October 6, 2004).
 
   
4.12
  Fourth Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed on October 6, 2004).
 
   
4.13
  Fifth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on March 3, 2005).
 
   
4.14
  Sixth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on March 3, 2005).
 
   
4.15
  Seventh Supplemental Indenture dated as of June 1, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.46 to Form 10-Q filed November 4, 2005).
 
   
4.16
  Eighth Supplemental Indenture dated as of July 18, 2006 to Indenture dated October 4, 2004 among Enterprise Products Operating L.P., as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to exhibit 4.2 to Form 8-K filed July 19, 2006).
 
   
4.17
  Ninth Supplemental Indenture, dated as of May 24, 2007, by and among Enterprise Products Operating L.P., as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007).
 
   
4.18
  Tenth Supplemental Indenture, dated as of June 30, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
 
   
4.19
  Eleventh Supplemental Indenture, dated as of September 4, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on September 5, 2007).
 
   
4.20
  Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).

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4.21
  Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 10-K filed March 31, 2003).
 
   
4.22
  Global Notes representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
 
   
4.23
  Global Note representing $500 million principal amount of 4.000% Series B Senior Notes due 2007 with attached Guarantee (incorporated by reference to Exhibit 4.14 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
 
4.24
  Global Note representing $500 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
 
   
4.25
  Global Note representing $150 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
 
   
4.26
  Global Note representing $350 million principal amount of 6.650% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
 
   
4.27
  Global Note representing $500 million principal amount of 4.625% Series B Senior Notes due 2009 with attached Guarantee (incorporated by reference to Exhibit 4.27 to Form 10-K for the year ended December 31, 2004 filed on March 15, 2005).
 
   
4.28
  Global Note representing $250,000,000 principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Form 10-Q filed on November 4, 2005).
 
   
4.29
  Global Note representing $250,000,000 principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed on November 4, 2005).
 
   
4.30
  Global Note representing $500,000,000 principal amount of 4.95% Senior Notes due 2010 with attached Guarantee (incorporated by reference to Exhibit 4.47 to Form 10-Q filed November 4, 2005).
 
   
4.31
  Form of Junior Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K file July 19, 2006).
 
   
4.32
  Global Note representing $800,000,000 principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 8, 2007).
 
   
4.33
  Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Form 8-K filed on July 1, 2005).
 
   
4.34
  Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007).
 
   
4.35
  First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (Incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006).
 
   
4.36
  Purchase Agreement, dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P. as Guarantor, and Enterprise Products Partners L.P., as buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006).
 
   
10.1
  Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998 (incorporated by reference to Exhibit 10.3 to Registration Statement Form S-1/A filed July 8, 1998).
 
   
10.2***
  Enterprise Products 1998 Long-Term Incentive Plan, amended and restated as of November 9 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed on November 8, 2007).
 
   
10.3***
  Form of Option Grant Award under Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 10-Q filed on November 8, 2007).

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10.4***
  Form of Restricted Unit Grant under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 10-Q filed on November 8, 2007).
 
   
10.5***
  EPE Unit L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P., Commission file no. 1-32610, on September 1, 2005).
 
   
10.6***
  First Amendment to EPE Unit L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.3 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
 
   
10.7***
  EPE Unit II, L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.13 to Form 10-K filed on February 28, 2007).
 
   
10.8***
  First Amendment to EPE Unit II, L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.4 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
 
   
10.9***
  EPE Unit III, L.P. Agreement of Limited Partnership dated May 7, 2007 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P. on May 10, 2007).
 
   
10.10***
  First Amendment to EPE Unit III, L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.5 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
 
   
10.11***
  Enterprise Products Company 2005 EPE Long-Term Incentive Plan (amended and restated) (incorporated by reference to Exhibit 10.1 to Form 8-K filed by Enterprise GP Holdings L.P. on May 8, 2006).
 
   
10.12***
  Form of Restricted Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.29 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
 
   
10.13***
  Form of Phantom Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.30 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
 
   
10.14***
  Form of Unit Appreciation Right Grant (Enterprise Products GP, LLC Directors) based upon the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed by Enterprise GP Holdings on May 8, 2006).
 
   
10.15***
  Enterprise Products 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit A to the Proxy Statement filed on December 31, 2007).
 
   
10.16
  Fourth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise Products GP, LLC, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated January 30, 2007, but effective as of February 5, 2007 (incorporated by reference to Exhibit 10 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
 
   
10.17
  First Amendment to the Fourth Amended and Restated Administrative Services Agreement dated February 28, 2007 (incorporated by reference to Exhibit 10.8 to Form 10-K filed on February 28, 2007).
 
   
10.18
  Second Amendment to Fourth Amended and Restated Administrative Services Agreement dated August 7, 2007, but effective as of May 7, 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
 
   
10.19
  Omnibus Agreement, dated as of February 5, 2007 by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership, L.P., Enterprise Lou-Tex Propylene Pipeline L.P., Sabine Propylene Pipeline L.P., Acadian Gas, LLC, Mont Belvieu Caverns, LLC, South Texas NGL Pipelines, LLC (incorporated by reference to Exhibit 10.19 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
 
   
10.20
  Contribution, Conveyance And Assumption Agreement dated as of February 5, 2007, by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC and DEP Operating Partnership, L.P. (incorporated by reference to Exhibit 1.1 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).

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10.21
  Agreement and Release, dated May 31, 2007, between EPCO, Inc. and Robert G. Phillips (incorporated by reference to Exhibit 10.3 to Form 10-Q filed on August 8, 2007).
 
   
10.22
  Revolving Credit Agreement, dated as of January 5, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.20 to Amendment No. 2 to Form S-1 Registration Statement (Reg. No. 333-138371) filed January 12, 2007).
 
   
10.23
  First Amendment to Revolving Credit Agreement, dated as of June 30, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners  (incorporated by reference to Exhibit 4.2 to Form 10-Q filed August 8, 2007 by Duncan Energy Partners). 
 
   
12.1#
  Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2007, 2006, 2005, 2004 and 2003.
 
   
21.1#
  List of subsidiaries as of February 1, 2008.
 
   
23.1#
  Consent of Deloitte & Touche LLP dated February 28, 2008.
 
   
31.1#
  Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the December 31, 2007 annual report on Form 10-K.
 
   
31.2#
  Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P. for the December 31, 2007 annual report on Form 10-K.
 
   
32.1#
  Section 1350 certification of Michael A. Creel for the December 31, 2007 annual report on Form 10-K.
 
   
32.2#
  Section 1350 certification of W. Randall Fowler for the December 31, 2007 annual report on Form 10-K.
 
*   With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323.
 
***   Identifies management contract and compensatory plan arrangements.
 
#   Filed with this report.

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SIGNATURES
          Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized on February 29, 2008.
             
    ENTERPRISE PRODUCTS PARTNERS L.P.    
 
      (A Delaware Limited Partnership)    
 
           
 
  By:   Enterprise Products GP, LLC, as general partner    
 
           
 
  By:   /s/ Michael J. Knesek
 
   
 
  Name:   Michael J. Knesek    
 
  Title:   Senior Vice President, Controller and    
 
                Principal Accounting Officer    
          Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated below on February 29, 2008.
     
Signature   Title (Position with Enterprise Products GP, LLC)
 
   
/s/ Dan L. Duncan
 
     Dan L. Duncan
  Director and Chairman
 
   
/s/ Michael A. Creel
 
     Michael A. Creel
  Director, President and Chief Executive Officer
 
   
/s/ W. Randall Fowler
 
     W. Randall Fowler
  Director, Executive Vice President and Chief Financial Officer
 
   
/s/ Richard H. Bachmann
 
     Richard H. Bachmann
  Director, Executive Vice President, Chief Legal Officer and Secretary
 
   
/s/ Dr. Ralph S. Cunningham
 
     Dr. Ralph S. Cunningham
  Director
 
   
/s/ E. William Barnett
 
     E. William Barnett
  Director
 
   
/s/ Charles M. Rampacek
 
     Charles M. Rampacek
  Director
 
   
/s/ Rex C. Ross
 
     Rex C. Ross
  Director
 
   
/s/ Michael J. Knesek
 
     Michael J. Knesek
  Senior Vice President, Controller and Principal Accounting Officer

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Exhibit Index
     
Exhibits   Description of Exhibits
2.1
  Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed December 15, 2003).
 
   
2.2
  Amendment No. 1 to Merger Agreement, dated as of August 31, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (incorporated by reference to Exhibit 2.1 to Form 8-K filed September 7, 2004).
 
   
2.3
  Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.2 to Form 8-K filed December 15, 2003).
 
   
2.4
  Amendment No. 1 to Parent Company Agreement, dated as of April 19, 2004, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (incorporated by reference to Exhibit 2.1 to the Form 8-K filed April 21, 2004).
 
   
2.5
  Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (incorporated by reference to Exhibit 2.4 to Form 8-K filed December 15, 2003).
 
   
3.1
  Certificate of Limited Partnership of Enterprise Products Partners L.P. (incorporated by reference to Exhibit 3.6 to Form 10-Q filed November 8, 2007).
 
   
3.2
  Fifth Amended and Restated Agreement of Limited Partnership of Enterprise Products Partners L.P., dated effective as of August 8, 2005 (incorporated by reference to Exhibit 3.1 to Form 8-K filed August 10, 2005).
 
   
3.3
  First Amendment to Fifth Amended and Restated Partnership Agreement of Enterprise Products Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Form 8-K/A filed January 3, 2008).
 
   
3.4
  Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of November 7, 2007 (incorporated by reference to Exhibit 3.2 to Form 10-Q filed November 8, 2007).
 
   
3.5
  Limited Liability Company Agreement of Enterprise Products Operating LLC dated as of June 30, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed on August 8, 2007).
 
   
3.6
  Certificate of Incorporation of Enterprise Products OLPGP, Inc., dated December 3, 2003 (incorporated by reference to Exhibit 3.5 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
 
   
3.7
  Bylaws of Enterprise Products OLPGP, Inc., dated December 8, 2003 (incorporated by reference to Exhibit 3.6 to Form S-4 Registration Statement, Reg. No. 333-121665, filed December 27, 2004).
 
   
3.8
  Certificate of Limited Partnership of Duncan Energy Partners L.P. (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P. Form S-1 Registration Statement, Reg. No. 333-138371, filed November 2, 2006).
 
   
3.9
  Amended and Restated Agreement of Limited Partnership of Duncan Energy Partners L.P., dated February 5, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K/A filed February 5, 2007).
 
   
3.10
  First Amendment to Amended and Restated Partnership Agreement of Duncan Energy Partners L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Duncan Energy Partners L.P.’s Form 8-K filed on January 3, 2008).
 
   
4.1
  Form of Common Unit certificate (incorporated by reference to Exhibit 4.1 to Registration Statement on Form S-1/A; File No. 333-52537, filed July 21, 1998).
 
   
4.2
  Indenture dated as of March 15, 2000, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and First Union National Bank, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed March 10, 2000).

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Exhibits   Description of Exhibits
4.3
  First Supplemental Indenture dated as of January 22, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
 
   
4.4
  Second Supplemental Indenture dated as of February 14, 2003, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wachovia Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 10-K filed March 31, 2003).
 
   
4.5
  Third Supplemental Indenture dated as of June 30, 2007, among Enterprise Products Operating LLC, as Issuer, Enterprise Products Partners L.P., as Guarantor, and U.S. Bank National Association, as successor Trustee (incorporated by reference to Exhibit 4.55 to Form 10-Q filed on August 8, 2007) .
 
   
4.6
  Amended and Restated Revolving Credit Agreement dated as of November 19, 2007 among Enterprise Products Operating LLC, the financial institutions party thereto as lenders, Wachovia Bank, National Association, as Administrative Agent, Issuing Bank and Swingline Lender, Citibank, N.A. and JPMorgan Chase Bank, as Co-Syndication Agents, and SunTrust Bank, Mizuho Corporate Bank, Ltd. and The Bank of Nova Scotia, as Co-Documentation Agents (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 20, 2007).
 
   
4.7
  Amended and Restated Guaranty Agreement dated as of November 19, 2007 executed by Enterprise Products Partners L.P. in favor of Wachovia Bank, National Association, as Administrative Agent (incorporated by reference to Exhibit 10.2 to Form 8-K filed on November 20, 2007).
 
   
4.8
  Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Form 8-K filed on October 6, 2004).
 
   
4.9
  First Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on October 6, 2004).
 
   
4.10
  Second Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on October 6, 2004).
 
   
4.11
  Third Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.4 to Form 8-K filed on October 6, 2004).
 
   
4.12
  Fourth Supplemental Indenture dated as of October 4, 2004, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to Form 8-K filed on October 6, 2004).
 
   
4.13
  Fifth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Form 8-K filed on March 3, 2005).
 
   
4.14
  Sixth Supplemental Indenture dated as of March 2, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on March 3, 2005).
 
   
4.15
  Seventh Supplemental Indenture dated as of June 1, 2005, among Enterprise Products Operating L.P., as Issuer, Enterprise Products Partners L.P., as Guarantor, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.46 to Form 10-Q filed November 4, 2005).

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Exhibits   Description of Exhibits
4.16
  Eighth Supplemental Indenture dated as of July 18, 2006 to Indenture dated October 4, 2004 among Enterprise Products Operating L.P., as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to exhibit 4.2 to Form 8-K filed July 19, 2006).
 
   
4.17
  Ninth Supplemental Indenture, dated as of May 24, 2007, by and among Enterprise Products Operating L.P., as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007).
 
   
4.18
  Tenth Supplemental Indenture, dated as of June 30, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.54 to Form 10-Q filed August 8, 2007).
 
   
4.19
  Eleventh Supplemental Indenture, dated as of September 4, 2007, by and among Enterprise Products Operating LLC, as issuer, Enterprise Products Partners L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 to Form 8-K filed on September 5, 2007).
 
   
4.20
  Global Note representing $350 million principal amount of 6.375% Series B Senior Notes due 2013 with attached Guarantee (incorporated by reference to Exhibit 4.4 to Registration Statement on Form S-4, Reg. No. 333-102776, filed January 28, 2003).
 
   
4.21
  Global Note representing $500 million principal amount of 6.875% Series B Senior Notes due 2033 with attached Guarantee (incorporated by reference to Exhibit 4.8 to Form 10-K filed March 31, 2003).
 
   
4.22
  Global Notes representing $450 million principal amount of 7.50% Senior Notes due 2011 (incorporated by reference to Exhibit 4.1 to Form 8-K filed January 25, 2001).
 
   
4.23
  Global Note representing $500 million principal amount of 4.000% Series B Senior Notes due 2007 with attached Guarantee (incorporated by reference to Exhibit 4.14 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
4.24
  Global Note representing $500 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.17 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
 
   
4.25
  Global Note representing $150 million principal amount of 5.600% Series B Senior Notes due 2014 with attached Guarantee (incorporated by reference to Exhibit 4.18 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
 
   
4.16
  Global Note representing $350 million principal amount of 6.650% Series B Senior Notes due 2034 with attached Guarantee (incorporated by reference to Exhibit 4.19 to Form S-3 Registration Statement Reg. No. 333-123150 filed on March 4, 2005).
 
   
4.27
  Global Note representing $500 million principal amount of 4.625% Series B Senior Notes due 2009 with attached Guarantee (incorporated by reference to Exhibit 4.27 to Form 10-K for the year ended December 31, 2004 filed on March 15, 2005).
 
   
4.28
  Global Note representing $250,000,000 principal amount of 5.00% Series B Senior Notes due 2015 with attached Guarantee (incorporated by reference to Exhibit 4.31 to Form 10-Q filed on November 4, 2005).
 
   
4.29
  Global Note representing $250,000,000 principal amount of 5.75% Series B Senior Notes due 2035 with attached Guarantee (incorporated by reference to Exhibit 4.32 to Form 10-Q filed on November 4, 2005).
 
   
4.30
  Global Note representing $500,000,000 principal amount of 4.95% Senior Notes due 2010 with attached Guarantee (incorporated by reference to Exhibit 4.47 to Form 10-Q filed November 4, 2005).
 
   
4.31
  Form of Junior Note, including Guarantee (incorporated by reference to Exhibit 4.3 to Form 8-K file July 19, 2006).
 
   
4.32
  Global Note representing $800,000,000 principal amount of 6.30% Senior Notes due 2017 with attached Guarantee (incorporated by reference to Exhibit 4.38 to Form 10-Q filed November 8, 2007).
 
   
4.33
  Amended and Restated Credit Agreement dated as of June 29, 2005, among Cameron Highway Oil Pipeline Company, the Lenders party thereto, and SunTrust Bank, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 4.1 to Form 8-K filed on July 1, 2005).

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Exhibits   Description of Exhibits
4.34
  Replacement Capital Covenant, dated May 24, 2007, executed by Enterprise Products Operating L.P. and Enterprise Products Partners L.P. in favor of the covered debtholders described therein (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by Enterprise Products Partners L.P. on May 24, 2007).
 
   
4.35
  First Amendment to Replacement Capital Covenant dated August 25, 2006, executed by Enterprise Products Operating L.P. in favor of the covered debtholders described therein (Incorporated by reference to Exhibit 99.2 to Form 8-K filed August 25, 2006).
 
   
4.36
  Purchase Agreement, dated as of July 12, 2006 between Cerrito Gathering Company, Ltd., Cerrito Gas Marketing, Ltd., Encinal Gathering, Ltd., as Sellers, Lewis Energy Group, L.P. as Guarantor, and Enterprise Products Partners L.P., as buyer (incorporated by reference to Exhibit 4.6 to Form 10-Q filed August 8, 2006).
 
   
10.1
  Transportation Contract between Enterprise Products Operating L.P. and Enterprise Transportation Company dated June 1, 1998 (incorporated by reference to Exhibit 10.3 to Registration Statement Form S-1/A filed July 8, 1998).
 
   
10.2***
  Enterprise Products 1998 Long-Term Incentive Plan, amended and restated as of November 9 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed on November 8, 2007).
 
   
10.3***
  Form of Option Grant Award under Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Form 10-Q filed on November 8, 2007).
 
   
10.4***
  Form of Restricted Unit Grant under the Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 10-Q filed on November 8, 2007).
 
   
10.5***
  EPE Unit L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P., Commission file no. 1-32610, on September 1, 2005).
 
   
10.6***
  First Amendment to EPE Unit L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.3 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
 
   
10.7***
  EPE Unit II, L.P. Agreement of Limited Partnership (incorporated by reference to Exhibit 10.13 to Form 10-K filed on February 28, 2007).
 
   
10.8***
  First Amendment to EPE Unit II, L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.4 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
 
   
10.9***
  EPE Unit III, L.P. Agreement of Limited Partnership dated May 7, 2007 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K filed by Enterprise GP Holdings L.P. on May 10, 2007).
 
   
10.10***
  First Amendment to EPE Unit III, L.P. Agreement of limited partnership dated August 7, 2007 (incorporated by reference to Exhibit 10.5 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
 
   
10.11***
  Enterprise Products Company 2005 EPE Long-Term Incentive Plan (amended and restated) (incorporated by reference to Exhibit 10.1 to Form 8-K filed by Enterprise GP Holdings L.P. on May 8, 2006).
 
   
10.12***
  Form of Restricted Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.29 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
 
   
10.13***
  Form of Phantom Unit Grant under the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.30 to Amendment No. 3 to Form S-1 Registration Statement (Reg. No. 333-124320) filed by Enterprise GP Holdings L.P. on August 11, 2005).
 
   
10.14***
  Form of Unit Appreciation Right Grant (Enterprise Products GP, LLC Directors) based upon the Enterprise Products Company 2005 EPE Long-Term Incentive Plan (incorporated by reference to Exhibit 10.3 to Form 8-K filed by Enterprise GP Holdings on May 8, 2006).
 
   
10.15
  Fourth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating L.P., Enterprise

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Exhibits   Description of Exhibits
 
  Products GP, LLC, Enterprise Products OLPGP, Inc., Enterprise GP Holdings L.P., EPE Holdings, LLC, DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership L.P., TEPPCO Partners, L.P., Texas Eastern Products Pipeline Company, LLC, TE Products Pipeline Company, Limited Partnership, TEPPCO Midstream Companies, L.P., TCTM, L.P. and TEPPCO GP, Inc. dated January 30, 2007, but effective as of February 5, 2007 (incorporated by reference to Exhibit 10 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
 
   
10.16
  First Amendment to the Fourth Amended and Restated Administrative Services Agreement dated February 28, 2007 (incorporated by reference to Exhibit 10.8 to Form 10-K filed on February 28, 2007).
 
   
10.17
  Second Amendment to Fourth Amended and Restated Administrative Services Agreement dated August 7, 2007, but effective as of May 7, 2007 (incorporated by reference to Exhibit 10.1 to Form 10-Q filed by Duncan Energy Partners L.P. on August 8, 2007).
 
   
10.18
  Omnibus Agreement, dated as of February 5, 2007 by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC, DEP Operating Partnership, L.P., Enterprise Lou-Tex Propylene Pipeline L.P., Sabine Propylene Pipeline L.P., Acadian Gas, LLC, Mont Belvieu Caverns, LLC, South Texas NGL Pipelines, LLC (incorporated by reference to Exhibit 10.19 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
 
   
10.19
  Contribution, Conveyance And Assumption Agreement dated as of February 5, 2007, by and among Enterprise Products Operating L.P., DEP Holdings, LLC, Duncan Energy Partners L.P., DEP OLPGP, LLC and DEP Operating Partnership, L.P. (incorporated by reference to Exhibit 1.1 to Form 8-K filed February 5, 2007 by Duncan Energy Partners).
 
   
10.20
  Agreement and Release, dated May 31, 2007, between EPCO, Inc. and Robert G. Phillips (incorporated by reference to Exhibit 10.3 to Form 10-Q filed on August 8, 2007).
 
   
10.21
  Revolving Credit Agreement, dated as of January 5, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 10.20 to Amendment No. 2 to Form S-1 Registration Statement (Reg. No. 333-138371) filed January 12, 2007).
 
   
10.22
  First Amendment to Revolving Credit Agreement, dated as of June 30, 2007, among Duncan Energy Partners L.P., as borrower, Wachovia Bank, National Association, as Administrative Agent, The Bank of Nova Scotia and Citibank, N.A., as Co-Syndication Agents, JPMorgan Chase Bank, N.A. and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents, and Wachovia Capital Markets, LLC, The Bank of Nova Scotia and Citigroup Global Markets Inc., as Joint Lead Arrangers and Joint Book Runners (incorporated by reference to Exhibit 4.2 to Form 10-Q filed August 8, 2007 by Duncan Energy Partners).
 
   
12.1#
  Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2007, 2006, 2005, 2004 and 2003.
 
   
21.1#
  List of subsidiaries as of February 1, 2008.
 
   
23.1#
  Consent of Deloitte & Touche LLP.
 
   
31.1#
  Sarbanes-Oxley Section 302 certification of Michael A. Creel for Enterprise Products Partners L.P. for the December 31, 2007 annual report on Form 10-K.
 
   
31.2#
  Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise Products Partners L.P. for the December 31, 2007 annual report on Form 10-K.
 
   
32.1#
  Section 1350 certification of Michael A. Creel for the December 31, 2007 annual report on Form 10-K.
 
   
32.2#
  Section 1350 certification of W. Randall Fowler for the December 31, 2007 annual report on Form 10-K.
 
*   With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission file number for Enterprise Products Partners L.P. is 1-14323.

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***   Identifies management contract and compensatory plan arrangements.
 
#   Filed with this report.

216