Edgar Filing: Enterprise GP Holdings L.P.

epeform10k_123108.htm

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, 2008

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: 1-32610

ENTERPRISE GP HOLDINGS L.P.

(Exact name of Registrant as Specified in Its Charter)

Delaware		13-4297064
(State or Other Jurisdiction of		(I.R.S. Employer Identification No.)
Incorporation or Organization)
	1100 Louisiana, 10th Floor, Houston, Texas 77002
	(Address of Principal Executive Offices) (Zip Code)

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

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

Title of Each Class	Name of Each Exchange On Which Registered
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 (§ 229.405 of this chapter) 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, 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.

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 Enterprise GP Holdings L.P.’s (or “EPE’s”) Units held by non-affiliates at June 30, 2008 was approximately $939.1 million, based on the closing price of such equity securities in the daily composite list for transactions on the New York Stock Exchange on June 30, 2008. This figure excludes Units beneficially owned by certain affiliates, including Dan L. Duncan. There were 139,191,640 Units of EPE outstanding at March 2, 2009.

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ENTERPRISE GP HOLDINGS L.P.

TABLE OF CONTENTS

		Page
		Number
PART I
Items 1 and 2.	Business and Properties.	3
Item 1A.	Risk Factors.	29
Item 1B.	Unresolved Staff Comments.	55
Item 3.	Legal Proceedings.	55
Item 4.	Submission of Matters to a Vote of Security Holders.	55

PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder
	Matters and Issuer Purchases of Equity Securities.	56
Item 6.	Selected Financial Data.	57
Item 7.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations.	58
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	91
Item 8.	Financial Statements and Supplementary Data.	100
Item 9.	Changes in and Disagreements with Accountants on Accounting and
	Financial Disclosure.	100
Item 9A.	Controls and Procedures.	100
Item 9B.	Other Information.	103

PART III
Item 10.	Directors, Executive Officers and Corporate Governance.	103
Item 11.	Executive Compensation.	109
Item 12.	Security Ownership of Certain Beneficial Owners and Management
	and Related Unitholder Matters.	119
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	122
Item 14.	Principal Accountant Fees and Services.	130

PART IV
Item 15.	Exhibits and Financial Statement Schedules.	131

Signatures		136
Financial Statements and Supplementary Data		F-1

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SIGNIFICANT RELATIONSHIPS REFERENCED

IN THIS ANNUAL REPORT

Unless the context requires otherwise, references to “we,” “us,” “our,” or the “Partnership” are intended to mean the business and operations of Enterprise GP Holdings L.P. and its consolidated subsidiaries.

References to the “Parent Company” mean Enterprise GP Holdings L.P., individually as the parent company, and not on a consolidated basis. The Parent Company is owned 99.99% by its limited partners and 0.01% by its general partner, EPE Holdings, LLC (“EPE Holdings”). EPE Holdings is a wholly owned subsidiary of Dan Duncan, LLC, the membership interests of which are owned by Dan L. Duncan.

References to “Enterprise Products Partners” mean Enterprise Products Partners L.P., the common units of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPD.” Enterprise Products Partners has no business activities outside those conducted by its operating subsidiary, Enterprise Products Operating LLC (“EPO”). References to “EPGP” refer to Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners. EPGP is owned by the Parent Company.

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.

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. TEPPCO GP is owned by the Parent Company.

References to “Energy Transfer Equity” mean the business and operations of Energy Transfer Equity, L.P. and its consolidated subsidiaries, which includes 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”). The Parent Company owns non-controlling interests in both Energy Transfer Equity and LE GP that it accounts for using the equity method of accounting.

References to “Employee Partnerships” mean EPE Unit L.P. (“EPE Unit I”), EPE Unit II, L.P. (“EPE Unit II”), EPE Unit III, L.P. (“EPE Unit III”), Enterprise Unit L.P. (“Enterprise Unit”), EPCO Unit L.P. (“EPCO Unit”), TEPPCO Unit L.P. (“TEPPCO Unit I”), and TEPPCO Unit II L.P. (“TEPPCO Unit II”), collectively, all of which are private company affiliates of EPCO, Inc.

References to “MLP Entities” mean Enterprise Products Partners, TEPPCO and Energy Transfer Equity.

References to “Controlled Entities” mean Enterprise Products Partners and TEPPCO. References to “Controlled GP Entities” mean TEPPCO GP and EPGP.

References to “EPCO” mean EPCO, Inc. and its private company affiliates, which are related party affiliates to all of the foregoing named entities. Mr. Duncan is the Group Co-Chairman and controlling shareholder of EPCO.

References to “DFI” mean Duncan Family Interests, Inc. and “DFIGP” mean DFI GP Holdings, L.P. DFI and DFIGP are private company affiliates of EPCO. The Parent Company acquired its ownership interests in TEPPCO and TEPPCO GP from DFI and DFIGP.

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The Parent Company, Enterprise Products Partners, EPGP, TEPPCO, TEPPCO GP, the Employee Partnerships, EPCO, DFI and DFIGP are affiliates under common control of Mr. Duncan. We do not control Energy Transfer Equity or LE GP.

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 EPE Holdings, as well as assumptions made by us and information currently available to us. When used in this document, words such as “anticipate,” “project,” “expect,” “plan,” “goal,” “forecast,” “intend,” “could,” “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 EPE Holdings believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor EPE Holdings 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

Enterprise GP Holdings L.P. is a publicly traded Delaware limited partnership, the limited partnership interests (the “Units”) of which are listed on the NYSE under the ticker symbol “EPE.” The business of Enterprise GP Holdings L.P. is the ownership of general and limited partner interests of publicly traded partnerships engaged in the midstream energy industry and related businesses. 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.enterprisegp.com.

Business Strategy

The primary objective of the Parent Company is to increase cash available for distributions to its unitholders and, accordingly, the value of its Units. In recent years, major independent oil and gas and other energy companies have divested significant midstream assets. In addition, there has been significant demand for the development of new midstream energy infrastructure to meet the needs of producers and consumers of natural gas, natural gas liquids (“NGLs”), crude oil and refined products. Finally, there have been several transactions involving the sale of general partner interests in publicly traded partnerships. These trends are generally expected to continue. The Parent Company seeks to capitalize on these trends by:

§	managing the entities that it controls (e.g. Enterprise Products Partners and TEPPCO) for the successful execution of their respective business activities, operations and strategies;

§	evaluating opportunities to acquire general partner interests and associated incentive distribution rights (“IDRs”) and related limited partner interests in publicly traded partnerships (e.g. Energy Transfer Equity and LE GP); and

§	evaluating opportunities to acquire assets and businesses in accordance with business opportunity agreements.

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Financial Information by Business Segment

Financial information for each of our reportable business segments is presented in Note 4 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. Such financial information is incorporated by reference into the description of Business in these Items 1 and 2.

Recent Developments

For information regarding our recent developments, see “Recent Developments” included under Item 7 of this annual report, which is incorporated by reference into this Item 1 and 2 discussion.

Basis of Presentation

In accordance with rules and regulations of the U.S. Securities and Exchange Commission (“SEC”) and various other accounting standard-setting organizations, our general purpose financial statements reflect the consolidation of the financial statements of businesses that we control through the ownership of general partner interests (e.g., Enterprise Products Partners and TEPPCO). Our general purpose consolidated financial statements present those investments in which we do not have a controlling interest as unconsolidated affiliates (e.g., Energy Transfer Equity and LE GP). To the extent that Enterprise Products Partners and TEPPCO reflect investments in unconsolidated affiliates in their respective consolidated financial statements, such investments will also be reflected as such in our general purpose financial statements unless subsequently consolidated by us due to common control considerations (e.g., Jonah Gas Gathering Company and the Texas Offshore Port System). Also, minority interest presented in our financial statements reflects third-party and related party ownership of our consolidated subsidiaries, which include the third-party and related party unitholders of Enterprise Products Partners, TEPPCO and Duncan Energy Partners other than the Parent Company. Unless noted otherwise, our discussions and analysis in this annual report are presented from the perspective of our consolidated businesses and operations.

In order for the unitholders of Enterprise GP Holdings L.P. and others to more fully understand the Parent Company’s business and financial statements on a standalone basis, certain sections of this annual report include information devoted exclusively to the Parent Company apart from that of our consolidated Partnership. A key difference between the non-consolidated Parent Company financial information and those of our consolidated Partnership is that the Parent Company views each of its investments (e.g., Enterprise Products Partners, TEPPCO and Energy Transfer Equity) as unconsolidated affiliates and records its share of the net income of each as equity earnings in the Parent Company income information. In accordance with U.S. generally accepted accounting principles (“GAAP”), we eliminate such equity earnings in the preparation of our consolidated Partnership financial statements.

Segment Discussion

Our investing activities are organized into business segments that reflect how the Chief Executive Officer of our general partner (i.e., our chief operating decision maker) routinely manages and reviews the financial performance of the Parent Company’s investments. We evaluate segment performance based on operating income. On a consolidated basis, we have three reportable business segments:

§	Investment in Enterprise Products Partners – Reflects the consolidated operations of Enterprise Products Partners and its general partner, EPGP. This segment also includes the development stage assets of the Texas Offshore Port System joint venture (as defined below).

In August 2008, Enterprise Products Partners, TEPPCO and Oiltanking Holding Americas, Inc. (“Oiltanking”), announced the formation of a joint venture (the “Texas Offshore Port System”) to design, construct, operate and own a Texas offshore crude oil port and a related onshore pipeline and storage system that would facilitate delivery of waterborne crude oil cargoes to refining centers located along the upper Texas Gulf Coast. Enterprise Products Partners, TEPPCO and

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Oiltanking each own, through their respective subsidiaries, a one-third interest in the joint venture.

Within their respective financial statements, TEPPCO and Enterprise Products Partners account for their individual ownership interests in the Texas Offshore Port System using the equity method of accounting. As a result of common control of TEPPCO and Enterprise Products Partners at the Parent Company level, the Texas Offshore Port System is a consolidated subsidiary of the Parent Company and Oiltanking’s interest in the joint venture is accounted for as minority interest. For financial reporting purposes, our management determined that the joint venture should be included within the Investment in Enterprise Products Partners’ segment.

§	Investment in TEPPCO – Reflects the consolidated operations of TEPPCO and its general partner, TEPPCO GP. This segment also includes the assets and operations of Jonah Gas Gathering Company (“Jonah”).

TEPPCO and Enterprise Products Partners are joint venture partners in Jonah, which owns a natural gas gathering system (the “Jonah system”) located in southwest Wyoming. Within their respective financial statements, Enterprise Products Partners and TEPPCO account for their individual ownership interests in Jonah using the equity method of accounting. As a result of common control of TEPPCO and Enterprise Products Partners at the Parent Company level, Jonah is a consolidated subsidiary of the Parent Company. For financial reporting purposes, our management determined that Jonah should be included within the Investment in TEPPCO segment.

§	Investment in Energy Transfer Equity – Reflects the Parent Company’s investments in Energy Transfer Equity and its general partner, LE GP. These investments were acquired in May 2007. The Parent Company accounts for these non-controlling investments using the equity method of accounting.

Each of the respective general partners of Enterprise Products Partners, TEPPCO and Energy Transfer Equity have separate operating management and boards of directors, with each board having at least three independent directors. We control Enterprise Products Partners and TEPPCO through our ownership of their respective general partners. We do not control Energy Transfer Equity or its general partner.

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 position are subject to a variety of risks. For information regarding our risk factors, see Item 1A of this annual report.

The business activities of the operating entities in which we own equity interests 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 consolidated businesses, see “Regulation” and “Environmental and Safety Matters” included within this Item 1 and 2 discussion.

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

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

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Our Major Customers

Our consolidated revenues are derived from a wide customer base. During 2008, 2007 and 2006, our largest customer was Valero Energy Corporation and its affiliates, which accounted for 11.2%, 8.9% and 9.3%, respectively, of our consolidated revenues.

Investment in Enterprise Products Partners

This segment reflects the consolidated business activities of Enterprise Products Partners and its general partner, EPGP. This segment also includes the development stage assets of the Texas Offshore Port System. At December 31, 2008, the Parent Company owned 13,670,925 common units of Enterprise Products Partners and 100% of the membership interests of EPGP. As a result of the Parent Company’s ownership of EPGP and common control considerations, the Parent Company consolidates Enterprise Products Partners and EPGP for financial reporting purposes.

EPGP

The business purpose of EPGP is to manage the affairs and operations of Enterprise Products Partners. EPGP has no separate business activities outside those conducted by Enterprise Products Partners. Through its ownership of EPGP, the Parent Company benefits from the IDRs held by EPGP.

EPGP is entitled to 2% of the cash distributions paid by Enterprise Products Partners as well as the associated IDRs of Enterprise Products Partners. EPGP’s percentage interest in Enterprise Products Partners’ quarterly cash distributions is increased through its ownership of the associated IDRs of Enterprise Products Partners, after certain specified target levels of distribution rates are met by Enterprise Products Partners. EPGP’s quarterly general partner and associated incentive distribution thresholds are as follows:

§	2.0% of quarterly cash distributions up to $0.253 per unit paid by Enterprise Products Partners;

§	15.0% of quarterly cash distributions from $0.253 per unit up to $0.3085 per unit paid by Enterprise Products Partners; and

§	25.0% of quarterly cash distributions that exceed $0.3085 per unit paid by Enterprise Products Partners.

For information regarding distributions received by the Parent Company from its general and limited partner interests in Enterprise Products Partners, see “Liquidity and Capital Resources – Cash Flow Analysis - Parent Company” included under Item 7 of this annual report.

Enterprise Products Partners

Enterprise Products Partners is a North American midstream energy company providing a wide range of services to producers and consumers of natural gas, NGLs, crude oil, and certain petrochemicals. In addition, Enterprise Products Partners is an industry leader in the development of pipeline and other midstream energy infrastructure in the continental United States and Gulf of Mexico.

Enterprise Products Partners operates in four business lines: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Offshore Pipelines & Services; and (iv) Petrochemical Services. The following sections summarize the activities and principal properties of each of these business lines.

NGL Pipelines & Services. This business line includes Enterprise Products Partners’ (i) natural gas processing business and related NGL marketing activities, (ii) NGL pipelines, (iii) NGL and related product storage facilities and (iv) NGL fractionation facilities. This business line also includes Enterprise Products Partners’ import and export terminal operations.

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Enterprise Products Partners’ natural gas processing business consists of 24 processing plants located in Colorado, Louisiana, Mississippi, New Mexico, Texas and Wyoming having a combined total gas processing capacity of approximately 15.3 Bcf/d (8.7 Bcf/d net to Enterprise Products Partners’ interest). These plants remove mixed NGLs from raw natural gas streams, thus enabling the natural gas to meet pipeline and commercial quality specifications. After extraction, mixed NGLs are transported to a fractionation facility for separation into purity NGL products such as ethane, propane, normal butane, isobutane and natural gasoline. Purity NGL products are used as raw materials by the petrochemical industry, feedstocks by refiners in the production of motor gasoline and by industrial and residential users as fuel. When operating and extracting costs incurred by natural gas processing plants are higher than the incremental value of the NGL products that would be extracted, 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, fractionation and marketing.

Through its NGL marketing activities, Enterprise Products Partners sells mixed and purity NGL products on spot and forward markets to meet contractual requirements. A significant portion of Enterprise Products Partners’ revenues are attributable to its NGL marketing activities. For the years ended December 31, 2008, 2007 and 2006, the sale of NGL products accounted for 67%, 69% and 67%, respectively, of Enterprise Products Partners’ revenues. The results of operations from Enterprise Products Partners’ natural gas processing business depend on processing spreads (i.e., the difference between (i) operating and extracting costs of the facility and (ii) either the processing fee charged or NGL sales price realized). Likewise, the results of operations of Enterprise Products Partners’ NGL marketing business depend on the margin between the cost of NGLs acquired and sales prices realized.

Enterprise Products Partners’ NGL pipeline, storage and terminalling operations include 14,322 miles of NGL pipelines, 157.2 MMBbls of working capacity of NGL and related product storage, and two import/export facilities. In general, Enterprise Products Partners’ NGL pipelines transport mixed NGLs and other hydrocarbons to fractionation plants and storage facilities; distribute and collect NGL products for petrochemical plants and refineries; and deliver propane to customers. Enterprise Products Partners’ NGL and related product underground storage wells are an integral part of its operations and are used to store its own products and those of customers.

Enterprise Products Partners’ most significant NGL pipeline is the 7,808-mile Mid-America Pipeline System. This regulated NGL pipeline system operates in thirteen states and consists 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. The Rocky Mountain pipeline transports mixed NGLs from the Rocky Mountain Overthrust and San Juan Basin areas to the Hobbs hub located on the Texas-New Mexico border. The Conway North segment links the NGL hub at Conway, Kansas to refineries, petrochemical plants and propane markets in the upper Midwest. The Conway North segment has access to NGL supplies from Canada’s Western Sedimentary Basin through third-party pipeline connections. The Conway South pipeline connects the Conway hub with Kansas refineries and transports NGLs from Conway, Kansas to the Hobbs hub. The Mid-America Pipeline System connects at the Hobbs hub with the 1,342-mile Seminole Pipeline, which is 90% owned by Enterprise Products Partners. The Seminole Pipeline is a regulated pipeline that transports NGLs from the Hobbs hub and the Permian Basin to markets in southeast Texas. Enterprise Products Partners also owns the 1,371-mile Dixie Pipeline, which is a regulated NGL pipeline that extends from southeast Texas and Louisiana to markets in the southeastern United States.

The results of operations from Enterprise Products Partners’ NGL pipelines are generally dependent upon the volume of product transported and the level of fees charged to customers. The transportation fees charged under these arrangements are either contractual or regulated by governmental agencies, including the Federal Energy Regulatory Commission (“FERC”). Typically, Enterprise Products Partners does not take title to the products transported by its NGL pipelines; rather, the shipper retains title and the associated commodity price risk.

Enterprise Product Partners’ most significant NGL and related product storage facility is located in Mont Belvieu, Texas, which is a key hub of the domestic and international NGL industry. This facility consists of 33 underground caverns with an aggregate storage capacity of approximately 100 MMBbls, a

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brine system with approximately 20 MMBbls of above-ground storage pit capacity and two brine production wells. This facility stores and delivers NGLs and certain petrochemical products for industrial customers located along the upper Texas Gulf Coast. Enterprise Products Partners’ has other NGL and related product storage facilities located primarily in Texas, Louisiana and Mississippi. The results of operations from Enterprise Products Partners’ NGL and related product storage operations are dependent upon the level of capacity reserved by customers, the volume of product injected and withdrawn from the storage facilities, and the level of fees charged.

Enterprise Products Partners owns or has interests in eight NGL fractionation facilities located in Texas and Louisiana that separate mixed NGLs into purity NGL products. Mixed NGLs from domestic natural gas processing plants represent the largest source of volumes fractionated by Enterprise Products Partners. Its most significant NGL fractionation facility is located in Mont Belvieu, Texas and has a total fractionation capacity of 230 MBPD (178 MBPD net to Enterprise Products Partners’ interest). 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 U.S. Gulf Coast. The results of operations from Enterprise Products Partners’ 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). Enterprise Products Partners is exposed to fluctuations in NGL prices (i.e., commodity price risk) to the extent it fractionates volumes for customers under percent-of-liquids arrangements. For information regarding Enterprise Products Partners’ use of commodity financial instruments to mitigate price and other risks, see “Commodity Risk Hedging Program” included under Item 7A of this annual report.

Enterprise Products Partners owns import and export facilities located on the Houston Ship Channel in southeast Texas. Its import facility can offload NGLs from tanker vessels at rates of up to 20,000 barrels per hour depending on the product. Its export facility can load cargoes of refrigerated propane and butane onto tanker vessels at rates of up to 6,700 barrels per hour. Enterprise Products Partners also owns a barge dock that can load or offload two barges of NGLs or refinery-grade propylene simultaneously at rates of up to 5,000 barrels per hour.

Enterprise Products Partners’ natural gas processing and NGL fractionation operations exhibit little to no seasonal variation. Results of operations from Enterprise Products Partners’ NGL pipelines are influenced by seasonal changes in propane demand for heating. Enterprise Products Partners’ plant locations along the U.S. Gulf Coast may be affected by weather events such as hurricanes. Underground storage facilities typically experience an increase in demand for services during the spring and summer months due to an increase in feedstock storage requirements in connection with motor gasoline production and a decrease in the fall and winter months when propane inventories are drawn to meet heating demand. Import terminal volumes peak during the spring and summer months and export terminal volumes are at their highest levels during the winter months.

Enterprise Products Partners’ natural gas processing 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. In the markets served by its NGL pipelines, Enterprise Products Partners competes with a number of intrastate and interstate liquids pipeline companies (including those affiliated with major oil, petrochemical and gas companies) and barge, rail and truck fleet operations. With respect to NGL fractionation services, Enterprise Products Partners competes with a number of facilities located in Texas, Louisiana and Kansas. Enterprise Products Partners’ competitors in the NGL and related product storage business are integrated major oil companies, chemical companies and other storage and pipeline companies. Its import and export terminals also compete with similar facilities operated by major oil and chemical companies.

Onshore Natural Gas Pipelines & Services. This business line includes (i) 18,346 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, (ii) underground natural gas storage caverns located in Mississippi, Louisiana and Texas, and (iii) natural gas marketing activities.

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The results of operations from this business line are generally dependent on the fees Enterprise Products Partners charges to transport and store natural gas and margins earned from the sale of natural gas.

Enterprise Products Partners’ onshore natural gas pipeline systems provide for the gathering and transmission of natural gas from some of the most prolific production areas in North America, including the Barnett Shale in north Texas and Piceance Basin in Colorado. Typically, these systems receive natural gas from producers or other parties through system interconnects and redeliver the natural gas to processing facilities, local gas distribution companies, industrial or municipal customers or to other onshore pipelines. The transportation fees charged for such services are either contractual or regulated by governmental agencies, including the FERC.

Enterprise Products Partners entered the natural gas marketing business in 2001 when it acquired the Acadian Gas System. Beginning in 2007, Enterprise Products Partners initiated an expansion of its natural gas marketing business to maximize the utilization of its portfolio of natural gas pipeline and storage assets. Enterprise Products Partners’ natural gas marketing activities generate revenues from the sale and delivery of natural gas obtained from (i) its natural gas processing plants, (ii) third party well-head purchases and (iii) the open market. In general, Enterprise Products Partners’ natural gas sales contracts utilize market-based pricing and incorporate pricing differentials for factors such as delivery location. Revenues from natural gas marketing activities accounted for 14%, 9% and 8% of Enterprise Products Partners’ consolidated revenues for the years ended December 31, 2008, 2007 and 2006, respectively. We expect Enterprise Products Partners’ natural gas marketing business to continue to expand in the future.

Enterprise Products Partners’ most significant onshore natural gas pipeline systems are its 7,860-mile Texas Intrastate System and 6,065-mile San Juan Gathering System. The Texas Intrastate System gathers and transports natural gas from supply basins in Texas (from both onshore and offshore sources) to local gas distribution companies and electric generation and industrial and municipal consumers. This system serves important natural gas producing regions and commercial markets in Texas, including Corpus Christi, the San Antonio/Austin area, the Beaumont/Orange area and the Houston area, including the Houston Ship Channel industrial market. The San Juan Gathering System serves natural gas producers in the San Juan Basin of New Mexico and Colorado. This system gathers natural gas from approximately 10,813 wells in the San Juan Basin and delivers the gas to processing facilities.

Enterprise Products Partners owns two underground natural gas storage caverns located in southern Mississippi that are capable of delivering in excess of 1.4 Bcf/d of natural gas (on a combined basis) into five interstate pipelines. Enterprise Products Partners also leases underground natural gas storage caverns in Texas and Louisiana. The total gross capacity of Enterprise Products Partners owned and leased natural gas storage facilities is 27.2 Bcf of natural gas.

Typically, Enterprise Products Partners’ onshore natural gas pipelines experience higher throughput rates during the summer months as natural gas-fired power generation facilities increase output for electricity for air conditioning. Likewise, seasonality impacts the injections and withdrawals at Enterprise Products Partners’ natural gas storage facilities. In the winter months, natural gas is needed as fuel for residential and commercial heating and during the summer months natural gas is needed by power generation facilities.

Within their market areas, Enterprise Products Partners’ onshore natural gas pipelines compete with other onshore natural gas pipelines on the basis of price (in terms of either transportation fees or natural gas selling prices), service and flexibility. Competition for natural gas storage is primarily based on location and ability to deliver natural gas in a timely and reliable manner.

Offshore Pipelines & Services. This business line includes Enterprise Products Partners’ offshore Gulf of Mexico assets consisting of (i) 1,544 miles of natural gas pipelines, (ii) 909 miles of crude oil pipeline systems and (iii) six multi-purpose hub platforms with crude oil or natural gas processing capabilities. The development stage assets of the Texas Offshore Port System are also included within this business line.

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Enterprise Products Partners’ most significant offshore natural gas pipeline systems are its 291-mile High Island Offshore System (“HIOS”), 162-mile Viosca Knoll Gathering System and the 134-mile Independence Trail pipeline. The HIOS pipeline system 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. This system includes eight pipeline junction and service platforms. This system also includes the 86-mile East Breaks System that connects HIOS to the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25.

The Viosca Knoll Gathering System transports natural gas from producing fields located in the Main Pass, Mississippi Canyon and Viosca Knoll areas of the Gulf of Mexico to several major interstate pipelines, including the Tennessee Gas, Columbia Gulf, Southern Natural, Transco, Dauphin Island Gathering System and Destin Pipelines.

The Independence Trail pipeline transports natural gas from the Independence Hub platform (described below) to the Tennessee Gas Pipeline. Natural gas transported on the Independence Trail pipeline originates from production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. Construction of the Independence Trail pipeline was completed in 2006 and, in July 2007, it received first production from deepwater wells connected to the Independence Hub platform.

Enterprise Products Partners’ 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 or other parties 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. The results of operations from Enterprise Products Partners’ offshore natural gas pipelines are generally dependent on the level of fees charged to customers for the gathering and transmission of natural gas.

Enterprise Products Partners owns interests in several offshore crude oil pipeline systems located in the Gulf of Mexico. These systems receive crude oil from offshore production developments and other pipelines and deliver the oil to various downstream locations. Enterprise Products Partners’ most significant offshore crude oil pipeline systems are its 374-mile Cameron Highway Oil Pipeline, 367-mile Poseidon Oil Pipeline System and 67-mile Constitution Oil Pipeline. 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. The Poseidon Oil Pipeline System gathers production from the outer continental shelf and deepwater areas of the Gulf of Mexico for delivery to onshore locations in south Louisiana. The Constitution Oil Pipeline serves the Constitution and Ticonderoga fields located in the central Gulf of Mexico. The Constitution Oil Pipeline connects with the Cameron Highway Oil Pipeline and Poseidon Oil Pipeline System at a pipeline junction platform.

The results of operations from Enterprise Products Partners’ offshore crude oil pipelines are dependent on the volume of crude oil to be delivered and the level of transportation fees charged. Enterprise Products Partners’ consolidated revenues generated by its offshore crude oil pipeline systems are generally attributable to long-term transportation agreements with producers.

Enterprise Products Partners has interests in six multi-purpose offshore hub platforms located in the Gulf of Mexico with crude oil and/or natural gas processing capabilities. Offshore platforms are critical components of energy-related 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 and 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.

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Enterprise Products Partners’ most significant offshore platforms are Independence Hub and Marco Polo. Independence Hub is located in Mississippi Canyon Block 920 in the eastern Gulf of Mexico. This platform processes natural gas gathered from deepwater production fields in the Atwater Valley, DeSoto Canyon, Lloyd Ridge and Mississippi Canyon areas of the Gulf of Mexico. The Independence Hub platform was successfully installed in March 2007 and began processing natural gas in July 2007. The Marco Polo platform, which is located in Green Canyon Block 608, 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.

The results of operations from Enterprise Products Partners’ offshore platforms are dependent on the level of demand payments and commodity fees charged. Demand fees represent charges to customers served by the 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 multiplied by the total volume of each product delivered. Contracts for platform services often include both demand payments and commodity charges.

Enterprise Products Partners’ 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.

Within their market areas, Enterprise Products Partners’ 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, 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. Enterprise Products Partners competes with other platform service providers on the basis of proximity and access to existing reserves and pipeline systems, as well as costs and rates.

In August 2008, Enterprise Products Partners, TEPPCO and Oiltanking formed the Texas Offshore Port System to design, construct, operate and own a Texas offshore crude oil port and a related onshore pipeline and storage system that would facilitate delivery of waterborne crude oil cargoes to refining centers located along the upper Texas Gulf Coast. Demand for such projects is being driven by planned and expected refinery expansions along the Gulf Coast, expected increases in shipping traffic and operating limitations of regional ship channels.

The joint venture’s primary project, referred to as “TOPS,” includes (i) an offshore port (which will be located approximately 36 miles from Freeport, Texas), (ii) an onshore storage facility with approximately 3.9 MMBbls of crude oil storage capacity and (iii) an 85-mile crude oil pipeline system having a transportation capacity of up to 1.8 MMBbls/d, that will extend from the offshore port to a storage facility near Texas City, Texas. The joint venture’s complementary project, referred to as the Port Arthur Crude Oil Express (or “PACE”) will transport crude oil from Texas City, including crude oil from TOPS, and will consist of a 75-mile pipeline and 1.2 MMBbls of crude oil storage capacity in the Port Arthur, Texas area. Development of the TOPS and PACE projects is supported by long-term contracts with affiliates of Motiva Enterprises LLC (“Motiva”) and Exxon Mobil Corporation (“Exxon Mobil”), which have committed a combined 725 MBPD of crude oil to the projects. The timing of the construction and related capital costs of the TOPS and PACE projects will be affected by the expansion plans of Motiva and the acquisition of requisite permits.

Enterprise Products Partners, TEPPCO and Oiltanking each own, through their respective subsidiaries, a one-third interest in the joint venture. A subsidiary of Enterprise Products Partners acts as construction manager and will act as operator for the joint venture. The aggregate cost of the TOPS and PACE projects is expected to be approximately $1.8 billion (excluding capitalized interest), with the majority of such capital expenditures currently expected to occur in 2010 and 2011. Enterprise Products Partners and TEPPCO have each guaranteed up to approximately $700.0 million, which includes a contingency amount for potential cost overruns, of the capital contribution obligations of their respective subsidiary partners in the joint venture.

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Petrochemical Services. This business line primarily includes (i) two propylene fractionation facilities, (ii) an isomerization complex, (iii) an octane additive production facility and (iv) 649 miles of petrochemical pipeline systems.

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

Enterprise Products Partners’ propylene fractionation facilities include (i) six polymer-grade fractionation units located in Mont Belvieu, Texas having a combined plant capacity of 87 MBPD (73 MBPD net to Enterprise Products Partners’ interest) and (ii) a chemical-grade fractionation plant located in Baton Rouge, Louisiana with a total plant capacity of 23 MPBD (7 MBPD net to Enterprise Products Partners’ interest). These operations also include 579 miles of propylene pipeline systems, an export terminal facility located on the Houston Ship Channel and petrochemical marketing activities.

Enterprise Products Partners’ commercial isomerization units convert normal butane into mixed butane, which is subsequently fractionated into isobutane, high purity isobutane and residual normal butane. 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.

Enterprise Products Partners’ isomerization business includes three butamer reactor units and eight associated deisobutanizer units located in Mont Belvieu, Texas, which comprise the largest commercial isomerization complex in the United States. This complex has a production capacity of 116 MBPD. This business also includes a 70-mile pipeline system used to transport high-purity isobutane from Mont Belvieu, Texas to Port Neches, Texas. The isomerization facility provides processing services to meet the needs of third-party customers and Enterprise Products Partners, including its NGL marketing activities and octane additive production facility.

Enterprise Products Partners owns and operates an octane additive production facility located in Mont Belvieu, Texas designed to produce 12 MBPD of petrochemical additives used in the production of reformulated motor gasoline blends. The facility produces isooctane and isobutylene using feedstocks of high-purity isobutane, which is supplied by Enterprise Products Partners’ isomerization units.

Results of operations from Enterprise Products Partners’ propylene fractionation and isomerization facilities are dependent upon the level of toll processing fees charged. Results of operations from petrochemical marketing activities and the octane additive production facility are dependent on the level of margins realized from the sale of products. In general, Enterprise Products Partners sells its petrochemical products at market-related prices, which may include pricing differentials for such factors as delivery location.

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

Enterprise Products Partners competes with numerous producers of polymer grade propylene, which include many of the major refiners and petrochemical companies located along the Gulf Coast. Generally, the propylene fractionation business competes in terms of the level of toll processing fees

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charged and access to pipeline and storage infrastructure. Enterprise Products Partners’ petrochemical marketing activities encounter competition from fully integrated oil companies and various petrochemical companies, and competition generally revolves around price, service, logistics and location.

With respect to its isomerization operations, Enterprise Products Partners competes 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. Enterprise Products Partners competes with other octane additive manufacturing companies primarily on the basis of price.

Major customers. Enterprise Products Partners’ revenues are derived from a wide customer base. During 2008, Enterprise Products Partners’ largest customer was LyondellBasell Industries (“LBI”) and its affiliates, which accounted for 9.6% of its consolidated revenues. In 2007 and 2006, Enterprise Products Partners’ largest customer was The Dow Chemical Company and its affiliates, which accounted for 6.9% and 6.1%, respectively, of Enterprise Products Partners’ consolidated revenues.

On January 6, 2009, LBI announced that its U.S. operations had voluntarily filed to reorganize under Chapter 11 of the U.S. Bankruptcy Code. At the time of the bankruptcy filing, Enterprise Products Partners had approximately $17.3 million of credit exposure to LBI, which was reduced to approximately $10.0 million through remedies provided under certain pipeline tariffs. In addition, Enterprise Products Partners is seeking to have LBI accept certain contracts and have filed claims pursuant to current Bankruptcy Court Orders that Enterprise Products Partners expects will allow it to recover the majority of the remaining credit exposure.

For 2008, LBI accounted for 10.2%, or $1.6 billion, of revenues attributable to Enterprise Products Partners’ NGL Pipelines & Services business line and 19.2%, or $516.2 million, of revenues attributable to Enterprise Products Partners’ Petrochemical Services business line.

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Utilization. The following table presents utilization data for Enterprise Products Partners’ principle assets for the periods indicated. These statistics are calculated on a net basis, taking into account Enterprise Products Partners’ ownership interests in certain joint ventures and reflect the periods in which it 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,
	2008			2007			2006
Investment in Enterprise Products Partners:
NGL Pipelines & Services:
Natural gas processing plants		64	%		66	%		56	%
NGL pipelines (MBPD) (1)		1,747			1,583			1,450
NGL import and export docks (MBPD) (1)		74			84			127
NGL fractionators		83	%		78	%		72	%
Onshore Natural Gas Pipelines & Services:
Onshore natural gas pipelines		64	%		62	%		71	%
Offshore Pipelines & Services:
Offshore natural gas pipelines		22	%		24	%		26	%
Offshore crude oil pipelines		20	%		19	%		18	%
Offshore natural gas processing		37	%		29	%		17	%
Offshore crude oil processing		17	%		26	%		19	%
Petrochemical Services:
Butane isomerization		74	%		78	%		70	%
Propylene fractionation		72	%		86	%		86	%
Octane enhancement		58	%		58	%		58	%
Petrochemical pipelines (MBPD) (1)		108			105			97

(1) The maximum number of barrels that Enterprise Products Partners’ liquids 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 liquids pipelines cannot be determined. Enterprise Products Partners measures the utilization rates of such pipelines in terms of net throughput (i.e., on a net basis in accordance with its consolidated ownership interest).

Investment in TEPPCO

This segment reflects the consolidated business activities of TEPPCO and its general partner, TEPPCO GP. This segment also reflects the assets and operations of Jonah. The Parent Company owns 4,400,000 common units of TEPPCO and 100% of the membership interests of TEPPCO GP. As a result of the Parent Company’s ownership of TEPPCO GP and common control considerations, the Parent Company consolidates TEPPCO and TEPPCO GP for financial reporting purposes.

Private company affiliates of EPCO under the common control of Mr. Duncan contributed 4,400,000 common units of TEPPCO and 100% of the membership interests of TEPPCO GP to the Parent Company in May 2007. As consideration for these contributions, the Parent Company issued 14,173,304 Class B Units and 16,000,000 Class C Units to these private company affiliates of EPCO. All of the Class B Units were converted into Units in July 2007. All of the Class C Units converted to Units on February 1, 2009 on a one-to-one basis. See Note 16 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for additional information regarding the Class C Units.

TEPPCO GP

The business purpose of TEPPCO GP is to manage the affairs and operations of TEPPCO. TEPPCO GP has no separate business activities outside those conducted by TEPPCO. Through its ownership of TEPPCO’s general partner, the Parent Company benefits from the IDRs held by TEPPCO GP.

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TEPPCO GP is entitled to 2% of the cash distributions paid by TEPPCO as well as the associated IDRs of TEPPCO. TEPPCO GP’s percentage interest in TEPPCO’s quarterly cash distributions is increased through its ownership of the associated IDRs, after certain specified target levels of distribution rates are met by TEPPCO. Currently, TEPPCO GP’s quarterly general partner and associated incentive distribution thresholds are as follows:

§	2% of quarterly cash distributions up to $0.275 per unit paid by TEPPCO;

§	15% of quarterly cash distributions from $0.275 per unit up to $0.325 per unit paid by TEPPCO; and

§	25% of quarterly cash distributions that exceed $0.325 per unit paid by TEPPCO.

Prior to December 2006, TEPPCO GP was entitled to 50% of any quarterly cash distributions paid by TEPPCO that exceeded $0.45 per unit. In December 2006, this maximum distribution tier was eliminated by TEPPCO as part of an amendment to its partnership agreement. In exchange for giving up this level of incentive distributions, TEPPCO issued 14,091,275 of its common units to TEPPCO GP, which were subsequently distributed to affiliates of EPCO.

For information regarding distributions received by the Parent Company from its general and limited partner interests in TEPPCO, see “Liquidity and Capital Resources – Parent Company” included under Item 7 of this annual report.

TEPPCO

TEPPCO is a North American midstream energy company that owns and operates (i) refined products, liquefied petroleum gas (“LPG”), petrochemical and NGL pipelines; (ii) natural gas gathering systems; and (iii) a marine transportation system. In addition, TEPPCO is engaged in the transportation, storage, gathering and marketing of crude oil, and has ownership interests in various joint venture projects.

TEPPCO operates in four business lines: (i) Downstream; (ii) Upstream; (iii) Midstream; and (iv) Marine Services. The following sections summarize the activities and principal properties of each of these business lines.

Downstream. This business line includes TEPPCO’s refined products and LPG transportation pipelines and related terminal operations. The results of operations from this business line are primarily dependent on the tariffs TEPPCO charges to transport refined products and LPGs. The tariffs charged for such services are either contractual or regulated by governmental agencies, including the FERC.

LPGs are a mixture of hydrocarbon gases used as a fuel in heating appliances and vehicles, and increasingly replace chlorofluorocarbons as an aerosol propellant and a refrigerant to reduce damage to the ozone layer. LPGs are produced as by-products of the crude oil refining process and in connection with natural gas production. LPGs exist in a liquid state only under pressure. Refined products represent output from refineries and include gasoline, diesel fuel, aviation fuel, kerosene, distillates and heating oil. Refined products also include blend stocks such as raffinate, natural gasoline and naphtha. Blend stocks are primarily used to produce gasoline or as a petrochemical plant feedstock.

TEPPCO’s most significant refined products and LPG pipeline is the 4,700-mile Products Pipeline System. This regulated pipeline system extends from southeast Texas through the central and midwestern U.S. to the northeastern U.S. The refined products and LPGs transported by the Products Pipeline System originate from refineries, interconnects with other pipelines, and bulk and marine terminals located principally along the southern end of the pipeline system. The Products Pipeline System includes 35 storage facilities with an aggregate storage capacity of 21 MMBbls of refined products and 6 MMBbls of LPGs. The system’s 63 delivery locations (20 of which are owned by TEPPCO) include facilities that provide customers with access to truck racks, railcars and marine vessels. Additionally, TEPPCO owns a 50% joint venture interest in the 794-mile Centennial pipeline system, which extends from southeast Texas

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to Illinois and is an integral part of the Products Pipeline System. The Centennial pipeline receives and delivers products from connecting TEPPCO pipelines and effectively loops TEPPCO’s Products Pipeline System. Looping TEPPCO’s Products Pipeline System permits effective supply of product to points south of Illinois as well as incremental product supply capacity to mid-continent markets downstream from southern Illinois.

In addition to pipelines, this business line includes TEPPCO’s refined product terminals. TEPPCO owns a marine receiving terminal located in Providence, Rhode Island, that includes a 400,000 barrel refrigerated storage tank along with ship unloading and truck loading facilities. TEPPCO’s Aberdeen, Mississippi facility, located along the Tennessee-Tombigbee waterway system, has storage capacity of 130,000 barrels for gasoline and diesel, which are supplied by barge for delivery to local markets. TEPPCO’s newly constructed Boligee, Alabama facility, which is also located along the Tennessee-Tombigbee waterway, commenced operations in August 2008. The Boligee terminal has storage capacity of 500,000 barrels for gasoline, diesel and ethanol, which are supplied by barge for delivery to local markets. The Boligee terminal also serves as an origination point for refined products delivered to TEPPCO’s Aberdeen terminal.

TEPPCO’s refined products and LPG businesses exhibit some seasonal variation. Gasoline demand is generally stronger in the spring and summer months and LPG demand is generally stronger in the fall and winter months. Weather and economic conditions in the geographic areas served by TEPPCO’s pipeline system also affect the demand for, and the mix of, the products delivered.

TEPPCO’s refined products and LPG pipelines face competition in the markets they serve from other pipelines. Competition among common carrier pipelines is based primarily on transportation charges, quality of customer service and proximity to end users. TEPPCO also faces competition from rail and pipeline movements of LPGs from Canada and waterborne imports into terminals located along the upper East Coast of the United States.

Upstream. This business line primarily includes TEPPCO’s crude oil gathering, transportation and storage business and related marketing activities principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. The operations of this business line also entail the distribution of lubrication oils and special chemicals.

TEPPCO’s crude oil business includes the purchase of crude oil from various producers and operators at the wellhead and bulk purchases of crude oil at pipeline interconnects, terminal facilities and trading locations. The crude oil is then sold to refiners and other customers. Crude oil is transported through proprietary gathering systems, common carrier pipelines, equity owned pipelines, trucking operations and third party pipelines. This business includes crude oil exchange activities, the purpose of which is to maximize margins or meet contract delivery requirements. The results of operations from this business line are generally dependent on the fees TEPPCO charges to transport and store crude oil. The fees charged for such services are either contractual or regulated by governmental agencies, including the FERC. TEPPCO also generates margins from the purchase and sale of crude oil.

The areas served by TEPPCO’s crude oil gathering and transportation operations are geographically diverse, and the factors that affect the supply of the products gathered and transported vary by region. Crude oil prices and production levels affect the supply of these products. The demand for gathering and transportation is affected by the demand for crude oil by refineries, refinery supply companies and similar customers in the regions served by this business line.

TEPPCO’s major crude oil pipelines include the 1,690-mile Red River System, 1,150-mile South Texas System and 500-mile Seaway pipeline. The Red River System extends from North Texas to South Oklahoma and includes facilities with 1.5 MMBbls of crude oil storage capacity. The South Texas System extends from South Central Texas to Houston, Texas and includes facilities with 1.1 MMBbls of crude oil storage capacity. TEPPCO owns a 50% joint venture interest in the Seaway pipeline, which extends from the Texas Gulf Coast to Cushing, Oklahoma and includes facilities with 6.8 MMBbls of crude oil storage

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capacity. Complementing these pipeline assets are crude oil terminals located in Cushing, Oklahoma and Midland, Texas.

TEPPCO’s Upstream business line faces competition from numerous sources, including common carrier and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies and other companies in the areas where TEPPCO’s pipeline systems receive and deliver crude oil. Competition among common carrier pipelines is based primarily on transportation charges, quality of customer service, competitive pricing, knowledge of products and markets, and proximity to refineries and other marketing hubs. The crude oil gathering and marketing business can be characterized by thin margins and strong competition for supplies of crude oil at the wellhead, and declines in domestic crude oil production have intensified this competition. TEPPCO’s upstream operations exhibit no seasonal variation.

Midstream. This business line includes TEPPCO’s midstream energy activities, which include NGL transportation and fractionation and Jonah’s natural gas gathering operations. The Jonah system consists of 714 miles of natural gas gathering pipelines located in the Greater Green River Basin of southwest Wyoming. Currently, the Jonah system has a transportation capacity of 2.4 Bcf/d, but will be being expanded to 2.6 Bcf/d by mid-2009 at an estimated cost of $125.0 million. The Jonah joint venture is owned approximately 80% by TEPPCO and approximately 20% by Enterprise Products Partners.

TEPPCO is also active in the San Juan Basin, where it serves natural gas producers in northern New Mexico and southern Colorado through its Val Verde Gathering System (“Val Verde”). Val Verde consists of approximately 400 miles of natural gas gathering pipelines with a capacity of 1.0 Bcf/d and an amine treating facility with a capacity of 550 MMcf/d. Val Verde is connected to two major interstate pipeline systems that serve the western United States.

TEPPCO also provides NGL transportation and fractionation services. TEPPCO’s major NGL pipelines include the 845-mile Chaparral pipeline and related 180-mile Quanah pipeline, the 189-mile Panola pipeline and a 155-mile portion of the Dean pipeline. The Chaparral pipeline, located in Texas and New Mexico, can deliver up to 118 MBPD of NGLs from West Texas and New Mexico to Mont Belvieu, Texas. The Quanah pipeline delivers NGLs to the Chaparral pipeline. The Panola and Dean pipelines also serve customers in Texas. TEPPCO has two small NGL fractionation facilities located in northeast Colorado. These two facilities are supported by a fixed-fee fractionation agreement with a third party that is in effect through 2018.

The results of operations from TEPPCO’s natural gas gathering and NGL pipelines are generally dependent upon the volume of product gathered or transported and the level of fees charged to customers. The fees charged under these arrangements are either contractual or regulated by governmental agencies, including the FERC. Typically, TEPPCO does not take title to the products transported in its pipelines; rather, the shipper retains title and the associated commodity price risk. The results of operations from TEPPCO’s NGL fractionation business are dependent upon the volume of mixed NGLs fractionated and the level of fractionation fees charged under fee-based contracts.

Typically, TEPPCO’s natural gas gathering systems experience higher throughput rates during the summer months as natural-gas fired power generation facilities increase output for electricity for air conditioning and in the winter months, natural gas is needed as fuel for residential and commercial heating. Historically, new well connections on the Jonah system were subject to seasonality as a result of winter range restrictions in the Pinedale field. Producers in the Pinedale field were prohibited from drilling activities typically during the November through April months due to wildlife restrictions and, as such, the Jonah system was limited in its ability to connect new wells to the system during that time. During 2008, the majority of these restrictions were lifted. TEPPCO’s other midstream operations exhibit little to no seasonal variation.

TEPPCO’s midstream operations compete largely on the basis of efficiency, system reliability, capacity, location and price. Key competitors in the gathering and treating segment include independent gas gatherers as well as other major integrated energy companies. TEPPCO’s NGL pipelines face

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competition from pipelines owned and operated by major oil and gas companies and other large independent pipeline companies.

Marine Services. This business line includes TEPPCO’s marine transportation business, which consists of (i) transporting refined products, crude oil, condensate and NGLs via tow boats and tank barges primarily on the U.S. inland waterway system and between domestic ports along the Gulf of Mexico Intracoastal Waterway and (ii) providing offshore support services for well-testing and pipelines located in the Gulf of Mexico. TEPPCO entered the marine transportation business in February 2008 when it acquired tow boats, tank barges and related assets from Cenac Towing Co, Inc. and affiliates (collectively, “Cenac”). At December 31, 2008, TEPPCO owned 105 inland barges and 45 inland tow boats. In addition, at December 31, 2008, TEPPCO owned eight offshore barges and six offshore tow boats. The results of operations from this business line are dependent upon the level of fees charged to transport cargo.

TEPPCO’s marine services operations exhibit some seasonal variation. Gasoline demand is generally stronger in the spring and summer months, which results in increased demand for TEPPCO’s marine transportation services during those seasons. Weather events, such as hurricanes and tropical storms in the Gulf of Mexico can adversely impact TEPPCO’s marine services business line. TEPPCO’s marine services business competes with other inland marine transportation companies as well as providers of other modes of transportation, such as rail tank cars, tractor-trailer tank trucks and, to a limited extent, pipelines.

Major customers. TEPPCO’s revenues are derived from a wide customer base. For the year ended December 31, 2008, Valero Energy Corp. (“Valero”), BP Oil Supply Company (“BP”) and Shell Trading Company (“Shell”) accounted for 21%, 16%, and 13%, respectively, of TEPPCO’s total consolidated revenues. For the year ended December 31, 2007, Valero, BP and Shell accounted for 16%, 14% and 12%, respectively, of TEPPCO’s total consolidated revenues. For the year ended December 31, 2006, Valero and BP accounted for 14% and 11%, respectively, of TEPPCO’s total consolidated revenues.

Utilization. The following table presents utilization data for TEPPCO’s principle assets for the periods indicated. These statistics are calculated on a net basis, taking into account TEPPCO’s ownership interests in certain joint ventures and reflect the periods in which it 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,
	2008			2007			2006
Investment in TEPPCO:
Downstream:
Refined Products transportation (MBPD) (1)		492			554			514
LPGs transportation (MBPD) (1)		106			115			123
Petrochemical transportation (MBPD) (1)		111			120			89
Upstream:
Crude oil pipelines (MBPD) (1)		697			646			678
Midstream:
Natural gas pipelines		83	%		82	%		78	%
NGL pipelines (MBPD) (1)		201			211			191
Marine Services:
Fleet utilization		93	%		n/a			n/a

(1) The maximum number of barrels that TEPPCO’s liquids 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 TEPPCO’s liquids pipelines cannot be determined. TEPPCO measures the utilization rates of such pipelines in terms of net throughput (i.e., on a net basis in accordance with its consolidated ownership interest).

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Investment in Energy Transfer Equity

This segment reflects the Parent Company’s non-controlling ownership interests in Energy Transfer Equity and its general partner, LE GP, both of which are accounted for using the equity method. In May 2007, the Parent Company paid $1.65 billion to acquire approximately 17.6% of the common units of Energy Transfer Equity, or 38,976,090 units, and approximately 34.9% of the membership interests of LE GP. On January 22, 2009, the Parent Company acquired an additional 5.7% membership interest in LE GP for $0.8 million, which increased our total ownership in LE GP to 40.6%.

LE GP

The business purpose of LE GP is to manage the affairs and operations of Energy Transfer Equity. LE GP has no separate business activities outside of those conducted by Energy Transfer Equity. The commercial management of Energy Transfer Equity does not overlap with that of Enterprise Products Partners or TEPPCO. LE GP owns a 0.31% general partner interest in Energy Transfer Equity and has no IDRs in the quarterly cash distributions of Energy Transfer Equity.

Energy Transfer Equity

Energy Transfer Equity has no separate operating activities apart from those of ETP. As of December 31, 2008, Energy Transfer Equity’s principal sources of distributable cash flow are its investments in the limited and general partner interests of ETP as follows:

§	Direct ownership of 62,500,797 ETP limited partner units, representing approximately 41% of ETP’s total outstanding common units.

§	Indirect ownership of the 2% general partner interest of ETP and all associated IDRs held by ETP’s general partner, of which Energy Transfer Equity owns 100% of the membership interests. Currently, the quarterly general partner and associated IDR thresholds of ETP’s general partner are as follows:

§	2% of quarterly cash distributions up to $0.275 per unit paid by ETP;

§	15% of quarterly cash distributions from $0.275 per unit up to $0.3175 per unit paid by ETP;

§	25% of quarterly cash distributions from $0.3175 per unit up to $0.4125 per unit paid by ETP; and

§	50% of quarterly cash distributions that exceed $0.4125 per unit paid by ETP.

ETP’s partnership agreement requires that it distribute all of its Available Cash (as defined in such agreement) within 45 days following the end of each fiscal quarter.

ETP is a publicly traded partnership (NYSE: ETP) owning and operating a diversified portfolio of midstream energy assets. ETP has pipeline operations in Arizona, Colorado, Louisiana, New Mexico and Utah, and owns the largest intrastate natural gas pipeline system in Texas. ETP’s natural gas operations include natural gas gathering and transportation pipelines, natural gas treating and processing assets and three natural gas storage facilities located in Texas. ETP is also one of the three largest retail marketers of propane in the United States, serving more than one million customers across the country. See Note 20 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for litigation matters involving ETP.

ETP operates in four business lines: (i) Midstream; (ii) Intrastate Transportation and Storage; (iii) Interstate Transportation; and (iv) Retail Propane. The following sections summarize the activities and principal properties of each of these business lines.

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Midstream. This business line includes ETP’s ownership and operation of approximately 6,700 miles of natural gas gathering pipelines, three natural gas processing plants, eleven natural gas treating facilities and eleven natural gas conditioning facilities. These facilities are located primarily in Texas, Utah and Colorado. The results of operations from this business line are primarily dependent on the level of fees charged in connection with ETP’s gathering, transportation and processing of natural gas and processing of NGLs. In addition, ETP generates margins from the marketing of natural gas to utilities, industrial consumers and other marketers and pipeline companies. ETP also utilizes financial instruments to generate income for this business line. These trading activities are limited in scope and in accordance with ETP’s commodity risk management policies.

Intrastate Transportation and Storage. This business line includes ETP’s approximately 7,800 miles of natural gas transportation pipelines, and three natural gas storage facilities. The results of operations from this business line are primarily dependent on the level of transportation fees charged by ETP and margins from natural gas sales made in connection with ETP’s HPL System.

The key assets within this business line are the HPL System and the ET Fuel System. The HPL System consists of approximately 4,200 miles of intrastate natural gas pipeline with an aggregate capacity of 5.5 Bcf/d and the Bammel underground storage reservoir and related transportation assets. The HPL System has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast of Texas, east Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The ET Fuel System is comprised of approximately 2,680 miles of intrastate natural gas pipelines and related storage facilities located in Texas. The ET Fuel System is located near high-growth production areas and provides ETP access to the Waha Hub near Midland, Texas, Katy Hub near Houston, Texas and Carthage Hub in east Texas.

Interstate Transportation. This business line includes ETP’s Transwestern pipeline and a 50% interest in a pipeline joint venture with Kinder Morgan Energy Partners L.P. (“Kinder Morgan”). The results of operations from ETP’s interstate pipelines are dependent on the level of natural gas transportation fees charged and operational gas sales margins. ETP expanded into this business in 2006 with the acquisition of the Transwestern pipeline.

The Transwestern pipeline is a FERC-regulated interstate natural gas pipeline extending approximately 2,700 miles from the gas producing regions of west Texas, eastern and northwest New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and pipeline interconnects at the California border. The Transwestern pipeline has access to three significant gas supply basins: the Permian Basin in west Texas and eastern New Mexico; the San Juan Basin in northwest New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandle. Natural gas sources from the San Juan Basin and surrounding producing areas can be delivered eastward to Texas intrastate and mid-continent connecting pipelines and natural gas market hubs as well as westward to markets in Arizona, Nevada and California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.

This business line also includes ETP’s joint development with Kinder Morgan of an approximately 500-mile interstate natural gas pipeline, the Midcontinent Express pipeline, the first phase of which is scheduled to be in service during the second quarter of 2009. This new pipeline will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco’s interstate natural gas pipeline in Butler, Alabama. The Transco pipeline delivers natural gas to significant markets in the northeast portion of the United States.

In October 2008, ETP entered into an agreement with Kinder Morgan for joint development of the Fayetteville Express pipeline, an approximately 187-mile pipeline that will originate in Conway County, Arkansas, continue eastward through White County, Arkansas and terminate at an interconnect with Trunkline Gas Company in Quitman County, Mississippi. Fayetteville Express Pipeline, LLC (“FEP”), the

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entity formed to own and operate this pipeline, initiated public review of the project pursuant to the FERC’s National Environmental Policy Act (“NEPA”) pre-filing review process in November 2008. The pipeline is expected to have an initial capacity of 2.0 Bcf/d. Pending necessary regulatory approvals, the pipeline project is expected to be in service by early 2011. FEP has secured binding 10-year commitments for transportation of approximately 1.85 Bcf/d. Pursuant to ETP’s agreement with Kinder Morgan related to this project, ETP and Kinder Morgan are each obligated to fund 50% of the equity necessary to construct the project.

In January 2009, ETP announced that it had entered into an agreement with Chesapeake Energy Marketing, Inc., a wholly-owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”) to construct the Tiger pipeline, a 178-mile 42-inch interstate natural gas pipeline. The Tiger pipeline will connect to ETP’s dual 42-inch pipeline system near Carthage, Texas extend through the heart of the Haynesville Shale and end near Delhi, Louisiana, with interconnects to at least seven interstate pipelines at various points in Louisiana. The Tiger pipeline is anticipated to have an initial throughput capacity of at least 1.25 Bcf/d, which capacity may be increased up to 2.0 Bcf/d based on the results of an open season. The agreement with Chesapeake provides for a 15-year commitment for firm transportation capacity of approximately 1.0 Bcf/d. The pipeline project is anticipated to cost between $1.0 billion and $1.2 billion, depending on the final throughput capacity design, with such costs to be incurred over a three-year period. Pending necessary regulatory approvals, the Tiger pipeline is expected to be in service in the first half of 2011.

ETP’s midstream, intrastate transportation and storage and interstate transportation businesses experience little to no effects from seasonality. ETP competes with other natural gas and NGL pipelines on the basis of location, capacity, price and reliability. ETP’s competitors include major integrated oil companies, interstate and intrastate pipelines and other companies that gather, compress, treat, process, transport and market natural gas. In marketing natural gas, ETP has numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely varying sizes, financial resources and experience.

Retail Propane. ETP, through its subsidiaries Heritage Operating, L.P. and Titan Energy Partners, L.P., is one of the three largest retail propane marketers in the United States based on gallons sold. ETP serves more than one million customers from approximately 440 customer service locations in approximately 40 states. ETP’s propane operations extend from coast-to-coast with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States. ETP’s propane business has grown primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth.

Retail propane is a margin-based business in which gross profits depend on the excess of sales price over propane supply cost. The market price of propane is often subject to volatile changes as a result of supply or other market conditions over which ETP has no control. Historically, ETP has generally been successful in maintaining retail gross margins on an annual basis despite changes in the wholesale cost of propane; however, there is no assurance that ETP will always be able to fully pass on product cost increases, particularly when product costs rise rapidly. Consequently, the profitability of ETP’s retail propane business is sensitive to changes in wholesale propane prices.

ETP’s propane business is seasonal and dependent upon weather conditions in its market areas. Historically, approximately two-thirds of ETP’s retail propane volume and substantially all of its propane-related operating income, is attributable to sales during the six-month peak-heating season of October through March. This pattern generally results in higher operating revenues and net income for ETP's retail propane business line during the period October through March of each year, and lower revenues and either net losses or lower net income during the period from April through September of each year. ETP’s cash flow from operations is generally greatest when customers pay for propane purchased during the six-month peak heating season. Sales to commercial and industrial customers are much less sensitive to changes in the weather.

Propane competes with other sources of energy, some of which are less costly for equivalent energy value. ETP competes for customers against suppliers of electricity, natural gas and fuel oil.

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Competition from alternative energy sources has been increasing as a result of reduced utility regulation. ETP also competes with other companies engaged in the retail propane distribution business. Competition in the propane industry is highly fragmented and generally occurs on a local basis with other large multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. The ability to compete effectively further depends on the reliability of service, responsiveness to customers and the ability to maintain competitive prices.

Title to Properties

We believe that Enterprise Products Partners and TEPPCO have satisfactory title to all of their material properties owned in fee or satisfactory rights pursuant to all of their material leases, easements, rights-of-way, permits and licenses to properties in which their interests are derived from these instruments. In certain cases, such properties are subject to liabilities such as contractual interests associated with the acquisition of the properties, liens for taxes not yet due, easements, restrictions and other minor encumbrances. We do not believe that such liabilities materially affect either the value of such properties or our ownership interests in such properties. Likewise, we believe that none of these liabilities will materially interfere with the use of such properties by Enterprise Products Partners and TEPPCO.

Capital Spending

For a discussion of the capital spending forecasts for Enterprise Products Partners and TEPPCO, see “Liquidity and Capital Resources” included under Item 7 of this annual report.

Weather-Related Risks

Regulation

Interstate Regulation

Liquids pipelines. Certain of Enterprise Products Partners’ and TEPPCO’s crude oil, petroleum products 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 and terms of service be filed with the FERC and posted publicly. Such rates may be based upon an indexing methodology, cost-of-service, competitive market showings or contractual arrangements with shippers.

The ICA permits interested persons to challenge proposed new or changed rates or rules and authorizes the FERC to investigate such changes 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 and related rules that are already in effect and may order a carrier to change them 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. Enterprise Products Partners and TEPPCO believe that the regulated rates charged by their interstate liquids pipelines are in accordance with the ICA. However, Enterprise Products Partners

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and TEPPCO cannot predict that such rates will not be challenged or at what levels they may be in the future.

Enterprise Products Partners’ Lou-Tex Propylene and Sabine Propylene Pipelines are interstate common carrier pipelines regulated under the ICA by the Surface Transportation Board (“STB”). 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.

Enterprise Products Partners’ Mid-America Pipeline Company, LLC (“Mid-America”) is currently involved in a rate case before the FERC. The case primarily involves shipper protests of rate increases on Mid-America's Conway North pipeline filed on March 31, 2005 and March 31, 2006. A hearing before an Administrative Law Judge began on October 2, 2007 and culminated with an initial decision on September 3, 2008. Briefs on Exceptions were filed October 31, 2008, with Briefs Opposing Exceptions filed on January 8, 2009. The matter is presently pending before the FERC, with a decision expected to be issued in the second half of 2009. We are unable to predict the outcome of this litigation.

Natural gas. Enterprise Products Partners’ and ETP’s natural gas storage facilities and interstate natural gas pipelines that provide services in interstate commerce are regulated by the FERC under the Natural Gas Act of 1938 (“NGA”). Under the NGA, rates for service must be just and reasonable and not unduly discriminatory. Enterprise Products Partners and ETP operate their respective assets subject to the NGA pursuant to tariffs that set forth rates and terms and conditions of service. These tariffs must be filed with and approved by the FERC pursuant to its regulations and orders. Approved tariff rates may be decreased on a prospective basis only by the FERC if it finds, on its own initiative, or as a result of challenges to the rates by third parties, that they are unjust, or unreasonable or otherwise unlawful. Unless the FERC grants specific authority to charge market-based rates, our rates are derived and charged based on a cost-of-service methodology.

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. The FERC’s rules require interstate pipelines and their affiliates to adhere to Standards of Conduct that, among other things, require that transmission employees function independently of marketing employees. The Energy Policy Act of 2005 amended the NGA to add an anti-manipulation provision. Pursuant to that act, the FERC established rules prohibiting energy market manipulation. A violation of these rules may subject us to civil penalties, disgorgement of unjust profits, or appropriate non-monetary remedies imposed by the FERC. In addition, the Energy Policy Act of 2005 amended the NGA and Natural Gas Policy Act of 1978 (“NGPA”) to increase civil and criminal penalties for any violation of the NGA, NGPA and any rules, regulations or orders of the FERC to up to $1.0 million per day per violation.

Offshore pipelines. Enterprise Products Partners’ offshore natural gas gathering pipeline systems and crude oil pipeline systems are subject to federal regulation under the Outer Continental Shelf Lands Act, which requires that all pipelines operating on or across the outer continental shelf provide nondiscriminatory transportation service.

Marine transportation. TEPPCO’s marine transportation business is subject to federal regulation under the Jones Act. The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels built and registered in the United States and owned and manned by United States citizens. The federal Merchant Marine Act of 1936 provides that, upon proclamation by the President of the United States of a national emergency or a threat to national security, the United States

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Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States citizens, including TEPPCO.

Intrastate Regulation

Certain intrastate NGL and natural gas pipelines owned by Enterprise Products Partners, TEPPCO and ETP are subject to regulation by state agencies. Some of these pipelines may also be subject to federal regulation. Under Section 311 of the NGPA and FERC’s regulations, an intrastate natural gas pipeline may transport gas for an interstate pipeline or any local distribution company served by an interstate pipeline under certain circumstances provided that such services are provided on an open and nondiscriminatory basis and the rates charged are fair and equitable.

Intrastate pipelines are subject to various regulations and statutes mandated by state regulatory authorities. Although the applicable state statutes and regulations vary, these generally require intrastate pipelines to 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 challenge the intrastate tariff rates and practices of Enterprise Products Partners, TEPPCO and ETP.

Sales of Natural Gas

ETP and Enterprise Products Partners are engaged in natural gas marketing activities. The resale of natural gas in interstate commerce is subject to FERC jurisdiction. However, under current federal rules 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 entities that engage in natural gas marketing are considered marketing affiliates of certain of our interstate natural gas pipelines. The FERC’s rules require interstate pipelines and their affiliates who sell natural gas in interstate commerce subject to the FERC’s jurisdiction to adhere to Standards of Conduct that, among other things, require that they function independently of each other. Pursuant to the Energy Policy Act of 2005, the FERC has also established rules prohibiting energy market manipulation. Those who violate the Standards on Conduct or these rules may be subject to civil penalties, suspension, or loss of authorization to perform such interstate natural gas sales, disgorgement of unjust profits, or other appropriate non-monetary remedies imposed by the FERC.

The FERC is continually proposing and implementing new rules and regulations affecting segments of the natural gas industry. For example, the FERC recently established rules requiring certain non-interstate pipelines to post daily scheduled volume information and design capacity for certain points, and has also required the annual reporting of gas sales information, in order to increase transparency in natural gas markets. In November 2008, the FERC commenced an inquiry into whether to expand the contract reporting requirements of Section 311 service providers. We cannot predict the ultimate impact of these regulatory changes on ETP’s or Enterprise Products Partners’ 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

The operations of the MLP Entities 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 Federal Clean Air Act; the Federal Water Pollution Control Act (or Clean Water Act); the Oil Pollution Act; and analogous state and local laws and regulations. Such laws and regulations affect many aspects of the MLP Entities present and future operations, and generally require the MLP Entities 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 the MLP Entities to fines, penalties and/or interruptions in their respective operations that could influence our

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consolidated results of operations. If an accidental leak, spill or release of hazardous substances occurs at a facility that one of the MLP Entities own, operate or otherwise use, or where it sends materials for treatment or disposal, the responsible party could be held jointly and severally liable for all resulting liabilities, including investigation, remedial and clean-up costs. Likewise, the responsible party 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 consolidated financial position, results of operations and cash flows.

We believe that the operations of the MLP Entities are in material compliance with applicable environmental and safety laws and regulations, other than certain matters discussed under Note 20 of the Notes to Consolidated Financial Statements included under Item 8 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 consolidated 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 customers of the MLP Entities, could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

Where we discuss our belief or knowledge with respect to Energy Transfer Equity’s or ETP’s compliance with laws and regulations, our statements are based solely on public disclosures by these entities and not on any independent inquiry with respect to these matters.

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 potential liability for the removal and remediation of pollutants.

The primary federal law for oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which addresses three principal areas of oil pollution: prevention, containment and cleanup, and liability. The 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 affects navigable waters, along shorelines or in the exclusive economic zone of the United States. Any unpermitted release of petroleum or other pollutants from the operations of the MLP Entities could also result in fines or penalties. The 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 Environmental Protection Agency (“EPA”), as appropriate.

Some states maintain groundwater protection programs that require permits for discharges or commercial operations that may impact groundwater conditions. Groundwater contamination resulting from spills or releases of petroleum products is an inherent risk within the midstream energy industry. To the extent that groundwater contamination requiring remediation exists along our pipeline systems as a result of past operations, 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.

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Air Emissions

The operations of the MLP Entities 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 facilities owned and/or operated by the MLP Entities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that the MLP Entities 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.

The MLP Entities’ 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 the MLP Entities to incur capital expenditures to add to or modify existing air emission control equipment and strategies. In addition, some of the facilities owned and/or operated by the MLP Entities are included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the Clean Air Act and many state laws. Failure by the MLP Entities to comply with these requirements could subject them to monetary penalties, injunctions, conditions or restrictions on operations, and enforcement actions. The MLP Entities may also be required to incur certain capital expenditures 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 consolidated financial position, results of operations and cash flows, and the requirements are not expected to be any more burdensome to the MLP Entities than to any other similarly situated companies.

Some recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have declined to wait on Congress to develop and implement climate control legislation and have already taken legal measures to reduce emissions of greenhouse gases. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA must consider whether it is required to regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Supreme Court’s position in the Massachusetts case that greenhouse gases fall under the federal Clean Air Act’s definition of “air pollutant” may also result in future regulation of greenhouse gas emissions from stationary sources under various Clean Air Act programs, including those that may be used in the operations of the MLP Entities. It is not possible at this time to predict how legislation that may be enacted to address greenhouse gas emissions would impact the MLP Entities. However, future laws and regulations could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our consolidated financial condition, results of operations and cash flows.

Solid Waste

In normal operations, the MLP Entities 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. The MLP Entities utilize waste minimization and recycling processes to reduce the waste volumes. Amendments to RCRA required the EPA to promulgate regulations banning the land disposal of all hazardous wastes unless the waste meets certain treatment standards or the land-disposal method meets certain waste containment criteria.

Environmental Remediation

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” imposes liability, without regard to fault or the legality of the original act, on

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certain classes of persons who contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where a release occurred, transporters that select the site of disposal of hazardous substances and companies that disposed of or arranged for the disposal of any hazardous substances found at a facility. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of the operations of the MLP Entities, their respective pipeline systems generate wastes that may fall within CERCLA’s definition of a “hazardous substance.” In the event a disposal facility previously used by any one of the MLP Entities requires clean up in the future, that entity 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

The MLP Entities 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 pipeline facilities. The HLPSA covers petroleum and petroleum products. The HLPSA requires any entity that owns or operates pipeline facilities to (i) comply with such regulations, (ii) permit access to and copying of records, (iii) file certain reports and (iv) provide information as required by the Secretary of Transportation.

The MLP Entities are also subject to DOT regulations 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.

In addition, the MLP Entities are 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 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. Enterprise Products Partners and TEPPCO have identified their respective HCA pipeline segments and developed appropriate Integrity Management Programs.

To our knowledge, we believe that the MLP Entities are in material compliance with the aforementioned pipeline safety matters.

Risk Management Plans

The MLP Entities 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 the MLP Entities 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. To our knowledge, we believe that the MLP Entities are operating in material compliance with their respective risk management program.

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Safety Matters

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

The MLP Entities 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. To our knowledge, we believe that the MLP Entities 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 the MLP Entities to organize and disclose information about the hazardous materials used in their operations. Certain parts of this information must be reported to employees, state and local governmental authorities and local citizens upon request.

National Fire Protection Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which ETP’s retail propane business operates. In some states, these laws are administered by state agencies, and in others they are administered on a municipal level. With respect to the transportation of propane by truck, ETP is subject to regulations governing the transportation of hazardous materials under the Federal Motor Carrier Safety Act, which is administered by the U.S. Department of Transportation. ETP conducts ongoing training programs to help ensure that its propane operations are in compliance with applicable regulations. ETP believes that the procedures in effect at its propane facilities for the handling, storage and distribution of propane are consistent with industry standards and are in substantial compliance with applicable laws and regulations.

Employees

Consistent with 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 (the “ASA”). For additional information regarding the ASA, see “EPCO Administrative Services Agreement” under Item 13 of this annual report. As of December 31, 2008, there were approximately 4,500 EPCO personnel who spend all or a portion of their time engaged in our consolidated businesses. Approximately 3,100 of these individuals devote all of their time performing management and operating duties for us. The remaining approximate 1,400 personnel are part of EPCO’s shared service organization and spend all or a portion of their time engaged in our consolidated businesses.

Available Information

As a large accelerated filer, we electronically file certain documents with the 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. Occasionally, 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 (800) SEC-0330. In addition, the SEC maintains an Internet website at www.sec.gov that contains reports and other information regarding registrants that file electronically with the SEC.

We provide electronic access to our periodic and current reports on our Internet website, www.enterprisegp.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.

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Additionally, Enterprise Products Partners, Duncan Energy Partners, TEPPCO, Energy Transfer Equity and ETP electronically file certain documents with the SEC, including annual reports on Form 10-K and quarterly reports on Form 10-Q. These entities also provide electronic access to their respective periodic and current reports on their Internet websites. The SEC file number for each registrant and company website address is as follows:

§	Enterprise Products Partners – SEC File No. 1-14323; website address: www.epplp.com

§	Duncan Energy Partners – SEC File No. 1-33266; website address: www.deplp.com

§	TEPPCO – SEC File No. 1-10403; website address: www.teppco.com

§	Energy Transfer Equity – SEC File No. 1-32740; website address: www.energytransfer.com

§	ETP – SEC File No. 1-11727; website address: www.energytransfer.com

Item 1A. Risk Factors.

An investment in our Units involves certain risks. If any of these risks were to occur, our business, financial position, results of operations and cash flows could be materially adversely affected. In that case, the trading price of our 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, financial position, results of operations and cash flows. We also recommend that investors read the “Risk Factors” sections of reports filed by each of Enterprise Products Partners, Duncan Energy Partners, TEPPCO and Energy Transfer Equity for more detailed information about risks specific to these investments that may impact our business, financial position, results of operations and cash flows.

Risks Inherent in an Investment in Us

The Parent Company’s operating cash flow is derived primarily from cash distributions it receives from each of the MLP Entities and the Controlled GP Entities.

The Parent Company’s operating cash flow is derived primarily from cash distributions it receives from each of the MLP Entities and the Controlled GP Entities. The amount of cash that each MLP Entity can distribute to its partners, including us and its general partner, each quarter principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter based on, among other things, the:

§	amount of hydrocarbons transported in its gathering and transmission pipelines;

§	throughput volumes in its processing and treating operations;

§	fees it charges and the margins it realizes for its services;

§	price of natural gas;

§	relationships among crude oil, natural gas and NGL prices, including differentials between regional markets;

§	fluctuations in its working capital needs;

§	level of its operating costs, including reimbursements to its general partner;

§	prevailing economic conditions; and

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§	level of competition in its business segments.

In addition, the actual amount of cash the MLP Entities will have available for distribution will depend on other factors, including:

§	the level of sustaining capital expenditures it makes;

§	the cost of any capital projects and acquisitions;

§	its debt service requirements and restrictions contained in its obligations for borrowed money; and

§	the amount of cash reserves established by EPGP, TEPPCO GP and LE GP for the proper conduct of Enterprise Products Partners’, TEPPCO’s and Energy Transfer Equity’s businesses, respectively.

We do not have any direct or indirect control over the cash distribution policies of Energy Transfer Equity or its general partner, LE GP.

Because of these factors, the MLP Entities may not have sufficient available cash each quarter to continue paying distributions at their current levels. Furthermore, the amount of cash that each of the MLP Entities has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items such as depreciation, amortization and provisions for asset impairments. As a result, the MLP Entities may be able to make cash distributions during periods when it records losses and may not be able to make cash distributions during periods when it records net income. See sections relating to specific risk factors of each of the MLP Entities included below for a discussion of further risks affecting the MLP Entities’ ability to generate distributable cash flow.

In the future, we may not have sufficient cash to pay distributions at our current distribution level or to increase distributions.

Because our primary source of operating cash flow is conditioned upon cash distributions from the MLP Entities, the amount of distributions we are able to make to our unitholders may fluctuate based on the level of distributions the MLP Entities makes to its partners. We cannot assure you that the MLP Entities will continue to make quarterly distributions at their current levels or will increase its quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our unitholders if the distributions of the MLP Entities increase or decrease, the timing and amount of such changes in distributions, if any, will not necessarily be comparable to the timing and amount of any changes in distributions made by the MLP Entities. Factors such as capital contributions, debt service requirements, general, administrative and other expenses, reserves for future distributions and other cash reserves established by the board of directors of EPE Holdings may affect the distributions we make to our unitholders. Prior to making any distributions to our unitholders, we will reimburse EPE Holdings and its affiliates for all direct and indirect expenses incurred by them on our behalf. EPE Holdings has the sole discretion to determine the amount of these reimbursed expenses. The reimbursement of these expenses, in addition to the other factors listed above, could adversely affect the level of distributions we make to our unitholders. We cannot guarantee that in the future we will be able to pay distributions or that any distributions we do make will be at or above our current quarterly distribution. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control or the control of EPE Holdings.

A significant amount of the distributions we receive are associated with general partner IDRs. Should Enterprise Products Partners, TEPPCO or ETP reduce their cash distributions to partners, this could have an adverse, disproportionate effect on the cash distributions we receive. This could result in a reduction in cash distributions to partners.

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Restrictions in our credit facility could limit our ability to make distributions to our unitholders.

Our credit facility contains covenants limiting our ability to take certain actions. This credit facility also contains covenants requiring us to maintain certain financial ratios. We are prohibited from making any distribution to our unitholders if such distribution would cause an event of default or otherwise violate a covenant under this credit facility. For more information about our credit facility, see Note 15 of the Notes to Consolidated Financial Statements included under Item 8 in this annual report.

Our unitholders do not elect our general partner or vote on our general partner’s officers or directors. Affiliates of our general partner currently own a sufficient number of Units to block any attempt to remove EPE Holdings as our general partner.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our unitholders do not have the ability to elect our general partner or the officers or directors of our general partner. Dan L. Duncan, through his control of Dan Duncan LLC, the sole member of EPE Holdings, controls our general partner and the election of all of the officers and directors of our general partner.

Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner or the officers or directors of our general partner. Our general partner may not be removed except upon the vote of the holders of at least 66 2/3% of our outstanding Units. Because affiliates of EPE Holdings own more than one-third of our outstanding Units, EPE Holdings currently cannot be removed without the consent of such affiliates. As a result, the price at which our Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

We may issue an unlimited number of limited partner interests without the consent of our unitholders, which will dilute your ownership interest in us and may increase the risk that we will not have sufficient available cash to maintain or increase our per Unit distribution level.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests without the consent of our unitholders. Such Units may be issued on the terms and conditions established in the sole discretion of our general partner. Any issuance of additional Units would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect market price of, units outstanding prior to such issuance. The payment of distributions on these additional Units may increase the risk that we will be unable to maintain or increase our current quarterly distribution.

The market price of our Units could be adversely affected by sales of substantial amounts of our units in the public markets, including sales by our existing unitholders.

Sales by certain of our existing unitholders of a substantial number of our Units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our Units or could impair our ability to obtain capital through an offering of equity securities. We do not know whether any such sale would be made in the public market or in a private placement, nor do we know what impact such potential or actual sales would have on our Unit price in the future.

Risks arising in connection with the execution of our business strategy may adversely affect our ability to make or increase distributions and/or the market price of our Units.

In addition to seeking to maximize distributions from the Controlled Entities, a principal focus of our business strategy includes acquiring general partner interests and associated incentive distribution rights and limited partner interests in publicly traded partnerships and, subject to our business opportunity agreements, acquiring assets and businesses that may or may not relate to the MLP Entities’ businesses. However, we may not be able to grow through acquisitions if we are unable to identify attractive

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acquisition opportunities or acquire identified targets. In addition, increased competition for acquisition opportunities may increase our cost of making acquisitions or cause us to refrain from making acquisitions.

If we are able to make future acquisitions, we may not be successful in integrating our acquisitions into our existing or future assets and businesses. Risks related to our acquisition strategy include but are not limited to:

§	the creation of conflicts of interests and competing fiduciary obligations that may inhibit our ability to grow or make additional acquisitions;

§	additional or increased regulatory or compliance obligations, including financial reporting obligations;

§	delays or unforeseen operational difficulties or diminished financial performance associated with the integration of new acquisitions, and the resulting delayed or diminished cash flows from such acquisitions;

§	inefficiencies and complexities that may arise due to unfamiliarity with new assets, businesses or markets;

§	conflicts with regard to the sharing of management responsibilities and allocation of time among overlapping officers, directors and other personnel;

§	the inability to hire, train and retain qualified personnel to manage and operate our growing business; and

§	the inability to obtain required financing for our existing business and new investment opportunities.

To the extent we pursue an acquisition that causes us to incur unexpected costs, or that fails to generate expected returns, our financial position, results of operations and cash flows may be adversely affected, and our ability to make distributions and/or the market price of our Units may be negatively impacted.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest in us to a third party in a merger 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 Dan Duncan LLC, as the sole member of EPE Holdings, to sell or transfer all or part of its ownership interest in EPE Holdings to a third party. The new owner of our general partner would then be in a position to replace the directors and officers of EPE Holdings.

Substantially all of our Units that are owned by EPCO and its affiliates and substantially all of the common units of Enterprise Products Partners and TEPPCO that are owned by EPCO and its affiliates are pledged as security under the credit facility of an affiliate of EPCO. Upon an event of default under this credit facility, a change in ownership or control of us, Enterprise Products Partners or TEPPCO could result.

Substantially all of our Units that are owned by EPCO and its affiliates and substantially all of the common units of Enterprise Products Partners (other than the 13,670,925 common units we currently own) and TEPPCO that are owned or controlled by EPCO Holdings, Inc. and its privately-held subsidiaries, are pledged as security under a credit facility of EPCO Holdings, Inc., a wholly owned indirect subsidiary of EPCO. This credit facility contains customary and other events of default relating to certain defaults of the borrower, us, Enterprise Products Partners, TEPPCO and other affiliates of EPCO. Upon an event of default, a change in control or ownership of us or Enterprise Products Partners or TEPPCO could result.

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Substantially all of the Parent Company’s assets are pledged under its credit facilities.

Borrowings under the Parent Company’s August 2007 Credit Agreement are secured by its ownership of (i) 13,454,498 common units of Enterprise Products Partners, (ii) 100% of the membership interests in EPGP, (iii) 38,976,090 common units of Energy Transfer Equity, (iv) 4,400,000 common units of TEPPCO and (v) 100% of the membership interests in TEPPCO GP. The Parent Company’s credit facilities contain customary and other events of default. Upon an event of default, the lenders under the Parent Company’s credit facilities could foreclose on its assets, which would have a material adverse effect on the Parent Company’s financial position, results of operations and cash flows. For additional information regarding the Parent Company’s debt obligations, see Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Our general partner has a limited call right that may require you to sell your Units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 90% of our outstanding Units, our general partner 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 Units held by unaffiliated persons at a price not less than their then-current market price. As a result, our unitholders may be required to sell their Units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of their Units. At March 2, 2009, affiliates of EPE Holdings, including Dan L. Duncan, EPCO and the Employee Partnerships, owned approximately 77.8% of our outstanding units.

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 each of EPE Holdings and EPGP. Mr. Duncan has been integral to our success and the success of EPCO due in part to his ability to identify and develop business opportunities, make strategic decisions and attract and retain key personnel. The loss of his leadership and involvement or the services of any key members of our senior management team could have a material adverse effect on our business, financial position, results of operations, cash flows and market price of our Units.

An increase in interest rates may cause the market price of our Units to decline.

As interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partnership interests. Reduced demand for our Units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our Units to decline.

The MLP Entities may issue additional common units, which may increase the risk that the MLP Entities will not have sufficient available cash to maintain or increase their per unit distribution level.

Each of the MLP Entities has wide latitude to issue additional common units on terms and conditions established by each of their respective general partners. The payment of distributions on those additional common units may increase the risk that the MLP Entities will be unable to maintain or increase their per unit distribution level, which in turn may impact the available cash that we have to distribute to our unitholders.

Unitholders’ liability as a limited partner may not be limited, and our unitholders may have to repay distributions or make additional contributions to us under certain circumstances.

As a limited partner in a partnership organized under Delaware law, our unitholders could be held liable for our obligations to the same extent as a general partner if they participate in the “control” of our

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business. EPE Holdings generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to EPE Holdings. Additionally, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in many jurisdictions.

Under certain circumstances, our unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, neither we nor any of the MLP Entities may make a distribution to our unitholders if the distribution would cause our or the MLP Entities’ respective liabilities to exceed the fair value of our respective assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the partnership for the distribution amount. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

We may have to take actions that are disruptive to our business strategy to avoid registration under the Investment Company Act of 1940.

The Investment Company Act of 1940, or Investment Company Act, requires registration for companies that are engaged primarily in the business of investing, reinvesting, owning, holding or trading in securities. Registration as an investment company would subject us to restrictions that are inconsistent with our fundamental business strategy.

A company may be deemed to be an investment company if it owns investment securities with a fair value exceeding 40% of the fair value of its total assets (excluding governmental securities and cash items) on an unconsolidated basis, unless an exemption or safe harbor applies. Securities issued by companies other than majority-owned subsidiaries are generally counted as investment securities for purposes of the Investment Company Act. We own minority equity interests in certain entities, including Energy Transfer Equity and LE GP, that could be counted as investment securities. In the event we acquire additional investment securities in the future, or if the fair value of our interests in companies that we do not control were to increase relative to the fair value of our Controlled Subsidiaries, we might be required to divest some of our non-controlled business interests, or take other action, in order to avoid being classified as an investment company. Similarly, we may be limited in our strategy to make future acquisitions of general partner interests and related limited partner interests to the extent they are counted as investment securities.

If we cease to manage and control either of the Controlled Entities and are deemed to be an investment company under the Investment Company Act of 1940, we may either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Securities and Exchange Commission, or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. As a result we would pay federal income tax on our taxable income at the corporate tax rate, distributions to our unitholders generally be taxed again as corporate distributions and none of our income, gains, losses or deductions available for distribution to unitholders would be substantially reduced. As a result, treatment of us as an investment company would result in a material reduction in distributions to our unitholders, which would materially reduce the value of our Units.

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Our partnership agreement restricts the rights of unitholders owning 20% or more of our Units.

Our unitholders’ voting rights are restricted by the provision in our partnership agreement generally providing that any Units held by a person that owns 20% or more of any class of Units then outstanding, other than EPE Holdings and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our 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, the price at which our Units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.

Risks Relating to Conflicts of Interest

Conflicts of interest exist and may arise among us, Enterprise Products Partners, TEPPCO and our respective general partners and affiliates and entities affiliated with any general partner interests that we may acquire in the future.

Conflicts of interest exist and may arise in the future as a result of the relationships among us, Enterprise Products Partners, TEPPCO and our respective general partners and affiliates. EPE Holdings is controlled by Dan Duncan LLC, of which Dan L. Duncan is the sole member. Accordingly, Mr. Duncan has the ability to elect, remove and replace the directors and officers of EPE Holdings. Similarly, through his indirect control of the general partner of Enterprise Products Partners and TEPPCO, Mr. Duncan has the ability to elect, remove and replace the directors and officers of the general partner of Enterprise Products Partners and TEPPCO. The assets of Enterprise Products Partners and TEPPCO overlap in certain areas, which may result in various conflicts of interest in the future.

EPE Holdings’ directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our partners. However, all of EPE Holdings’ executive officers and non-independent directors (excluding O.S. Andras and Randa Duncan Williams) also serve as executive officers or directors of EPGP and, as a result, have fiduciary duties to manage the business of Enterprise Products Partners in a manner beneficial to Enterprise Products Partners and its partners. Consequently, these directors and officers may encounter situations in which their fiduciary obligations to Enterprise Products Partners, on the one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

Future conflicts of interest may arise among us and any entities whose general partner interests we or our affiliates acquire or among Enterprise Products Partners, TEPPCO and such entities. It is not possible to predict the nature or extent of these potential future conflicts of interest at this time, nor is it possible to determine how we will address and resolve any such future conflicts of interest. However, the resolution of these conflicts may not always be in our best interest or that of our unitholders.

If we are presented with certain business opportunities, Enterprise Products Partners (for itself or Duncan Energy Partners) will have the first right to pursue such opportunities.

Pursuant to an administrative services agreement, we have agreed to certain business opportunity arrangements to address potential conflicts that may arise among us, Enterprise Products Partners and the EPCO Group (which includes EPCO and its affiliates, excluding EPGP, Enterprise Products Partners and its subsidiaries (including Duncan Energy Partners), us and EPE Holdings and TEPPCO, its general partner and their controlled affiliates). If a business opportunity in respect of any assets other than equity securities, which we generally define to include general partner interests in publicly traded partnerships and similar interests and associated incentive distribution rights and limited partner interests or similar interests owned by the owner of such general partner or its affiliates, is presented to the EPCO Group, us, EPE Holdings, EPGP or Enterprise Products Partners, then Enterprise Products Partners (for itself or Duncan Energy Partners) will have the first right to acquire such assets. The administrative services agreement provides, among other things, that Enterprise Products Partners (for itself or Duncan Energy Partners) will be presumed to desire to acquire the assets until such time as it advises the EPCO Group and us that it has abandoned the pursuit of such business opportunity, and we may not pursue the acquisition of such assets

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prior to that time. These business opportunity arrangements limit our ability to pursue acquisitions of assets that are not “equity securities.”

Our general partner’s affiliates may compete with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement and subject to certain business opportunity agreements, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us and our unitholders, which may permit them to favor their own interests to the detriment of us and our unitholders.

At March 2, 2009, Dan L. Duncan, EPCO and their controlled affiliates, including the Employee Partnerships, owned approximately 77.8% of our outstanding Units, and Dan Duncan LLC owned 100% of EPE Holdings. Dan Duncan serves as EPE Holdings’ Chairman as well as the Chairman of EPGP. Conflicts of interest may arise among EPE Holdings and its affiliates, including TEPPCO, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, EPE Holdings may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following:

EPE Holdings is allowed to take into account the interests of parties other than us, including EPCO, EPGP, Enterprise Products Partners, TEPPCO GP, TEPPCO and their respective affiliates and any future general partners and limited partnerships acquired in the future in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our Units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

§	our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution to our unitholders;

§	our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us;

§	our general partner controls the enforcement of obligations owed to us by it and its affiliates; and

§	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Our partnership agreement limits our general partner’s fiduciary duties to us and our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

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permits EPE Holdings to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles EPE Holdings to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

§	provides that our general partner is entitled to make other decisions in “good faith” if it reasonably believes that the decision is in our best interests;

generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Audit, Conflicts and Governance Committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

In order to become a limited partner of our partnership, our unitholders are required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.

Each of the Controlled GP Entities controls its respective Controlled Entity and may influence cash distributed to us.

Although we are the sole member of each of the Controlled GP Entities, our control over the Controlled Entities’ actions is limited. The fiduciary duties owed by each of the Controlled GP Entities to each of their respective Controlled Entities and its unitholders prevent us from influencing the Controlled GP Entities to take any action that would benefit us to the detriment of the Controlled Entities or its unitholders. For example, each of the Controlled GP Entities makes business determinations on behalf of their respective Controlled Entities that impact the amount of cash distributed by each of the Controlled Entities to its unitholders and to its respective Controlled GP Entities, which in turn, affects the amount of cash distributions we receive from the Controlled Entities and the Controlled GP Entities and consequently, the amount of distributions we can pay to our unitholders.

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, financial position and results of operations.

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

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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 the MLP Entities’ Business

Since our cash flows primarily consist exclusively of distributions from the MLP Entities, risks to the MLP Entities’ businesses are also risks to us. We have set forth below some, but not all, of the key risks to the MLP Entities’ businesses, the occurrence of which could have negative impact on the MLP Entities’ financial performance and decrease the amount of cash they are able to distribute to us, thereby impacting the amount of cash that we are able to distribute to our unitholders. These key risks are not in terms of importance or level of risk. In some instances, each of the MLP Entities share similar risks. However, in some cases, certain risks are specific to the businesses of Enterprise Products Partners, TEPPCO and Energy Transfer Equity. These risks will be discussed separately, when necessary. Any risks related to Energy Transfer Equity will refer to the business of ETP since the business of Energy Transfer Equity is to receive distributions from ETP.

Enterprise Products Partners and TEPPCO recently announced their participation in the Texas Offshore Port System joint venture. Like other projects for new facilities, the Texas Offshore Port System joint venture is subject to various business, operational and regulatory risks and may not be successful.

The Texas Offshore Port System joint venture (including the TOPS and PACE projects thereunder) is expected to represent an important investment for Enterprise Products Partners and TEPPCO, requiring an estimated combined $1.2 billion in capital contributions from them (excluding capitalized interest). Either or both Enterprise Products Partners and TEPPCO may be unable to make required capital contributions due to an inability to access capital markets or otherwise, in which event the non-contributing partner’s interest could be diluted, and such partner could suffer other adverse consequences.

Commencement of the Texas Offshore Port System joint venture operations, like other new facilities, is also subject to obtaining necessary regulatory and third-party approvals. The offshore terminal will require approval by the U.S. Coast Guard and issuance of a Deepwater Port License, while the onshore pipeline and storage facilities will be subject to review by the U.S. Environmental Protection Agency, Army Corps of Engineers and Department of Transportation. Obtaining such approvals is a time consuming process. For example, management estimates that the Deepwater Port License could take as long as two years, assuming there are no delaying factors. These and other regulatory, environmental, political and legal risks are beyond the control of Enterprise Products Partners or TEPPCO and may also require the expenditure of unexpected amounts of capital.

The Texas Offshore Port System joint venture is also subject to significant logistical, technological and staffing requirements, as well as force majeure events such as hurricanes along the Gulf Coast, that could result in delays or significant increases in the project’s current estimated costs. Increased project costs or delays due to any cause, including financial, regulatory, environmental, political, legal, economic or logistical difficulties, could have a material adverse effect on the success of the Texas Offshore Port System joint venture and on our business, financial position, results of operations and prospects.

The interruption of distributions to the MLP Entities from their respective subsidiaries and joint ventures may affect their ability to satisfy their obligations and to make distributions to their partners.

Each of the MLP Entities is a partnership holding company with no business operations and its operating subsidiaries conduct all of its operations and own all of its operating assets. The only significant

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assets that each MLP Entity owns are the ownership interests in its subsidiaries and joint ventures. As a result, each MLP Entity depends upon the earnings and cash flow of its subsidiaries and joint ventures and the distribution of that cash in order to meet its obligations and to allow it to make distributions to its partners. The ability of an MLP Entity’s subsidiaries and joint ventures to make distributions 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.

In addition, the charter documents governing each of the MLP Entities’ 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 such MLP Entity participates 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 the MLP Entities under certain circumstances. Accordingly, each of the MLP Entities’ joint ventures may be unable to make distributions to it at current levels, if at all.

Changes in demand for and production of hydrocarbon products may materially adversely affect the MLP Entities’ financial position, results of operations and cash flows.

The MLP Entities operate predominantly in the midstream energy sector, which includes gathering, transporting, processing, fractionating and storing natural gas, NGLs, crude oil and refined products. As such, the financial position, results of operations and cash flows of each of the MLP Entities may be materially adversely affected by changes in the prices of these hydrocarbon products and by changes in the relative price levels among these hydrocarbon products.

Changes in prices and changes in the relative price levels may impact demand for hydrocarbon products, which in turn may impact production and volumes of product for which each of the MLP Entities provide services. An MLP Entity may also incur price risk to the extent counterparties do not perform in connection with its marketing of crude oil, natural gas, NGLs and propylene, as applicable.

In the past, the price of natural gas has been extremely volatile, and this volatility may continue. The New York Mercantile Exchange daily settlement price for natural gas for the prompt month contract in 2006 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. In 2008, the same index ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu.

Generally, the prices of natural gas, NGLs, crude oil and other hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors that are impossible to control. These factors include but are not limited to:

§	the level of domestic production;

§	the availability of imported oil and natural gas;

§	actions taken by foreign oil and natural gas producing nations;

§	the availability of transportation systems with adequate capacity;

§	the availability of competitive fuels;

§	fluctuating and seasonal demand for oil, natural gas and NGLs;

§	the impact of conservation efforts;

§	the extent of governmental regulation and taxation of production; and

§	the overall economic environment.

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A decline in the volume of natural gas, NGLs and crude oil delivered to the MLP Entities’ facilities could adversely affect its financial position, results of operations and cash flows.

The MLP Entities’ profitability could be materially impacted by a decline in the volume of natural gas, NGLs and crude oil transported, gathered or processed at their 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 the MLP Entities’ facilities.

The crude oil, natural gas and NGLs currently transported, gathered or processed at the MLP Entities’ facilities originate from existing domestic and international resource basins, which naturally deplete over time. To offset this natural decline, the MLP Entities’ 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 the MLP Entities’ 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 the MLP Entities’ facilities are located. This could result in a decrease in volumes to the MLP Entities’ offshore platforms, natural gas processing plants, natural gas, crude oil and NGL pipelines, and NGL fractionators, which would have a material adverse affect on the MLP Entities’ financial position, results of operations cash flows. Additional reserves, if discovered, may not be developed in the near future or at all.

In addition, imported liquefied natural gas (“LNG”) is expected to be a significant component of future natural gas supply to the United States. Much of this increase in LNG supplies is expected to be imported through new LNG facilities to be developed over the next decade. Twelve LNG projects have been approved by the FERC to be constructed in the Gulf Coast region and an additional two LNG projects have been proposed for the region. We cannot predict which, if any, of these projects will be constructed. The MLP Entities may not realize expected increases in future natural gas supply available to their 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 the MLP Entities’ assets or (iv) they do not influence sources of supply on the MLP Entities’ systems. If the expected increase in natural gas supply through imported LNG is not realized, projected natural gas throughput on the MLP Entities’ pipelines would decline, which could have a material adverse effect on the MLP Entities’ results of operations, cash flows and financial position.

Acquisitions that appear to be accretive may nevertheless reduce the MLP Entities’ cash from operations on a per unit basis.

Even if the MLP Entities make acquisitions that they believe will be accretive, these acquisitions may nevertheless reduce 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 acquired businesses;

§	decreased liquidity as a result of using a significant portion of available cash or borrowing capacity to finance the acquisition;

§	a significant increase in interest expense or financial leverage if additional debt is incurred to finance the acquisition;

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§	the assumption of known or unknown liabilities for which there is no indemnification or for which indemnity is inadequate or limited;

§	an inability to hire, train or retain qualified personnel to manage and operate new businesses and assets;

§	mistaken assumptions about the overall costs of equity or debt;

§	the diversion of management’s and employees’ attention from other business concerns;

§	unforeseen difficulties operating in new product areas or new geographic areas; and

§	customer or key employee losses at the acquired businesses.

If any of the MLP Entities consummates any future acquisitions, its 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 it will consider in determining the application of these funds and other resources.

The MLP Entities may not be able to fully execute their growth strategies if they encounter illiquid capital markets or increased competition for investment opportunities.

Each of the MLP Entities’ have a strategy that contemplates growth through the development and acquisition of a wide range of midstream and other energy infrastructure assets while maintaining a strong balance sheet. These strategies include constructing and acquiring additional assets and businesses to enhance the ability to compete effectively and diversifying its asset portfolio, thereby providing more stable cash flow. Each of the MLP Entities regularly considers and enters into discussions regarding, and is currently contemplating and/or pursuing, potential joint ventures, stand alone projects or other transactions that it believes will present opportunities to realize synergies, expand its role in the energy infrastructure business and increase its market position.

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

Recent conditions in the financial markets have limited the MLP Entities’ ability to access equity and credit markets. Generally, credit has become more expensive and difficult to obtain, and the cost of equity capital has also become more expensive. Some lenders are imposing more stringent credit terms and there may be a general reduction in the amount of credit available in the markets in which we and the MLP Entities conduct business. Tightening of the credit markets may have a material adverse effect on us and the MLP Entities by, among other things, decreasing our ability to finance expansion projects or business acquisitions on favorable terms and by the imposition of increasingly restrictive borrowing covenants. In addition, the distribution yields of new equity issued either by us or the MLP Entities may be at a higher yield than historical levels, making additional equity issuances more expensive.

In addition, each of the MLP Entities is experiencing increased competition for the types of assets and businesses it has historically purchased or acquired. Increased competition for a limited pool of assets could result in the MLP Entities losing to other bidders more often or acquiring assets at less attractive prices. Either occurrence would limit the affected MLP Entity’s ability to fully execute its growth strategy.

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The inability of any MLP Entity to execute its growth strategy may materially adversely affect its ability to maintain or pay higher distributions in the future.

The global financial crisis may have impacts on our business and financial position that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system has had, and may continue to have, an impact on our business and financial position. We may face significant challenges if conditions in the financial markets revert to those that existed in the fourth quarter of 2008. The ability of Enterprise Products Partners, TEPPCO and ETP to access the capital markets may be severely restricted at a time when they would like, or need, to do so, which could have an adverse impact on their ability to meet capital commitments and achieve the flexibility needed to react to changing economic and business conditions. The credit crisis could have a negative impact on lenders or customers of Enterprise Products Partners, TEPPCO or ETP, causing such parties to fail to meet their obligations. Additionally, demand for the services and products of Enterprise Products Partners, TEPPCO and ETP depends on activity and expenditure levels in the energy industry, which are directly and negatively impacted by depressed oil and gas prices. Also, a decrease in demand for NGLs by petrochemical and refining industries due to a decrease in demand for their products due to general economic conditions would impact demand for services and products of Enterprise Products Partners, TEPPCO and ETP. Any of these factors could lead to reduced usage of the pipelines and energy logistics services of Enterprise Products Partners, TEPPCO and ETP, which could have a material negative impact on our financial position, results of operations, cash flows and prospects.

Increases in interest rates could materially adversely affect the MLP Entities’ business, financial position, results of operations and cash flows.

We, including Energy Transfer Equity, have significant exposure to increases in interest rates. At December 31, 2008, Parent Company debt was $1.08 billion, of which $500.0 million was at fixed interest rates and the remainder at variable interest rates, after giving effect to existing interest rate swap agreements. At December 31, 2008, the principal amount of Enterprise Products Partners’ consolidated debt was $9.05 billion, of which $7.48 billion was at fixed interest rates and $1.57 billion was at variable interest rates, after giving effect to existing interest rate swap arrangements. At December 31, 2008, the principal amount of TEPPCO’s consolidated debt was $2.52 billion, of which $2.00 billion was at fixed interest rates and $516.7 million was at variable interest rates. Energy Transfer Equity reported $7.2 billion of consolidated debt, which includes debt with variable interest rates, in their annual report on Form 10-K for the period ended December 31, 2008.

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 financial position, results of operations and cash flows 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 limited partnership Units. Any such reduction in demand for our equity securities resulting from other more attractive investment opportunities may cause the trading price of our securities to decline.

The MLP Entities’ future debt level may limit their flexibility to obtain additional financing and pursue other business opportunities.

The amount of any of the MLP Entities’ future debt could have significant effects on its operations, including, among other things:

a substantial portion of the MLP Entities’ cash flow, including that of Duncan Energy Partners to Enterprise Products Partners, could be dedicated to the payment of principal and interest on its future debt and may not be available for other purposes, including the payment of distributions on its common units and capital expenditures;

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§	credit rating agencies may view its debt level negatively;

§	covenants contained in its existing and future credit and debt arrangements will require it to continue to meet financial tests that may adversely affect its flexibility in planning for and reacting to changes in its business, including possible acquisition opportunities;

§	its 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;

§	it may be at a competitive disadvantage relative to similar companies that have less debt; and

§	it may be more vulnerable to adverse economic and industry conditions as a result of its significant debt level.

Each of the MLP Entities’ ability to access capital markets to raise capital on favorable terms will be affected by its debt level, the amount of its debt maturing in the next several years and current maturities, and by prevailing market conditions. Moreover, if the rating agencies were to downgrade any of the MLP Entities’ credit rating, then the MLP Entity could experience an increase in its borrowing costs, difficulty assessing capital markets or a reduction in the market price of its common units. Such a development could adversely affect the MLP Entity’s ability to obtain financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness. If any of the MLP Entities’ is unable to access the capital markets on favorable terms in the future, it might be forced to seek extensions for some of its short-term securities or to refinance some of its debt obligations through bank credit, as opposed to long-term public debt securities or equity securities. The price and terms upon which the MLP Entities 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 such MLP Entity’s leverage may adversely affect its future financial and operating flexibility and thereby impact its ability to pay cash distributions at expected rates.

The MLP Entities face competition from third parties in their midstream businesses.

Even if crude oil and natural gas reserves exist in the areas accessed by the MLP Entities’ facilities and are ultimately produced, the MLP Entities may not be chosen by the producers in these areas to gather, transport, process, fractionate, store or otherwise handle the hydrocarbons that are produced. The MLP Entities 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.

The MLP Entities’ refined products transportation business competes with other pipelines in the areas where it deliver products. The MLP Entities also compete with trucks, barges and railroads in some of the areas it serves. Competitive pressures may adversely affect the MLP Entities’ tariff rates or volumes shipped. The crude oil gathering and marketing business can be characterized by thin margins and intense competition for supplies of crude oil at the wellhead. A decline in domestic crude oil production has intensified competition among gatherers and marketers. Enterprise Products Partners’ and TEPPCO’s crude oil transportation business competes with common carriers and proprietary pipelines owned and

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operated by major oil companies, large independent pipeline companies and other companies in the areas where such MLP Entities’ pipeline systems deliver crude oil and NGLs.

In the MLP Entities’ natural gas gathering business, new supplies of natural gas are necessary to offset natural declines in production from wells connected to its gathering systems and to increase throughput volume, and it encounters competition in obtaining contracts to gather natural gas supplies. Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and price arrangements. The MLP Entities’ key competitors in the gas gathering segment include independent gas gatherers and major integrated energy companies. Alternate gathering facilities are available to producers they serve, and those producers may also elect to construct proprietary gas gathering systems. If the production delivered to any of the MLP Entities’ gathering system declines, its revenues from such operations will decline.

The use of derivative financial instruments could result in material financial losses by each of the MLP Entities.

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

The MLP Entities’ 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 each of the MLP Entities intends to grow its 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 its control and may require the expenditure of significant amounts of capital. These potential risks include, among other things, the following:

§	the MLP Entity 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;

§	the MLP Entity will not receive any material increases in revenues until the project is completed, even though it may have expended considerable funds during the construction phase, which may be prolonged;

§	the MLP Entity may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize;

since the MLP Entities are not engaged in the exploration for and development of natural gas reserves, it may not have access to third-party estimates of reserves in an area prior to its constructing facilities in the area. As a result, the MLP Entities may construct facilities in an area where the reserves are materially lower than it anticipate;

§	where the MLP Entities 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

§	the MLP Entities may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may not be economical.

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

The MLP Entities’ growth strategy may adversely affect its results of operations if it does not successfully integrate the businesses that it acquires or if it substantially increases its indebtedness and contingent liabilities to make acquisitions.

Each of the MLP Entities’ growth strategy includes making accretive acquisitions. As a result, from time to time, each of the MLP Entities will evaluate and acquire assets and businesses that it believes complement its existing operations. Any of the MLP Entities may be unable to integrate successfully businesses it acquires in the future. Any of the MLP Entities may incur substantial expenses or encounter delays or other problems in connection with its growth strategy that could negatively impact its financial position, results of operations and cash flows. 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 required to be maintained under the Sarbanes-Oxley Act of 2002;

§	managing relationships with new joint venture partners;

§	inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including with their markets; and

§	diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.

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

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

Some of the MLP Entities’ operations involve risks of personal injury, property damage and environmental damage, which could curtail their operations and otherwise materially adversely affect cash flow. For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 pounds per square inch. Enterprise Products Partners also operates oil and natural gas facilities located underwater in the Gulf of Mexico, which can involve complexities, such as extreme water pressure. Virtually all of the MLP Entities’ operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes. The location of their assets and 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 the MLP Entities or that deliver oil, natural gas or other products to them are damaged by severe weather or any other disaster, accident, catastrophe or event, the MLP Entities’ operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply the MLP Entities’ facilities or other stoppages arising

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from factors beyond their control. These interruptions might involve significant damage to people, property or the environment, and repairs might take from a week or less for a minor incident to six months or more for a major interruption. Additionally, some of the storage contracts that the MLP Entities are a party to obligate such MLP Entities’ to indemnify customers for any damage or injury occurring during the period in which the customers’ products is in their possession. Any event that interrupts the revenues generated by the MLP Entities’ operations, or which causes them to make significant expenditures not covered by insurance, could reduce cash available for paying distributions and, accordingly, adversely affect the market price of their common units.

We believe that the MLP Entities have adequate insurance coverage, 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 hurricanes in 2005 and 2008 have made it more difficult for the Controlled Entities to obtain certain types of coverage. As a result, EPCO and LE GP may not be able to renew existing insurance policies on behalf of the MLP Entities or procure other desirable insurance on commercially reasonable terms, if at all. If the MLP Entities were to incur a significant liability for which they were not fully insured, a material adverse effect on their financial position, results of operations and cash flows could occur. 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.

Federal or state regulation could materially adversely affect the MLP Entities’ business, financial position, results of operations and cash flows.

The FERC, pursuant to the ICA, the Energy Policy Act and rules and orders promulgated thereunder, regulates the tariff rates for the MLP Entities’ interstate common carrier pipeline operations, including the transportation of crude oil, NGLs, petrochemical products and refined products. Pursuant to the NGA, the FERC also regulates the MLP Entities’ interstate natural gas pipeline and storage facilities. The Surface Transportation Board (“STB”), pursuant to the ICA, regulates interstate propylene pipelines. State regulatory agencies, such as the Texas Railroad Commission (“TRRC”), regulate the MLP Entities’ intrastate natural gas and NGL pipelines, intrastate natural gas storage facilities and natural gas gathering lines.

Under the ICA, interstate tariffs must be just and reasonable and must not be unduly discriminatory or confer an undue preference upon any shipper. In addition, interstate transportation rates must be filed with the FERC and publicly posted. Shippers may protest, and the FERC may investigate, the lawfulness of new or changed tariff rates. The FERC can suspend those tariff rates for up to seven months. It can also require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful. The FERC and interested parties may challenge tariff rates that have become final and effective. Because of the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of the rates charged by the MLP Entities could adversely affect their revenues.

The Energy Policy Act deemed liquid 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., deemed grandfathered). Some, but not all, of the MLP Entities’ interstate rates are considered grandfathered rates under the Energy Policy Act. A person challenging a grandfathered rate must, as a threshold matter, establish a substantial change since the date of enactment of the Energy Policy Act, in either the economic circumstances or the nature of the service that formed the basis of the rate. In May 2007, the D. C. Circuit upheld the FERC’s view that a substantial change in the economic circumstances requires a change to the pipeline’s total cost of service rather than to a single cost element. A successful challenge to the grandfathered rates charged by the MLP Entities could adversely affect their revenues.

The FERC uses several prescribed rate methodologies for approving regulated tariff rates under the ICA. Some of the MLP Entities’ interstate tariff rates are market-based and others are derived in

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accordance with the FERC’s indexing methodology, which currently allows a pipeline to increase its rates by a percentage linked to the Producer Price Index for finished goods. These methodologies may limit the ability to set rates based on actual costs or may delay the use of rates reflecting increased costs. Changes in the FERC’s approved methodology for approving rates could adversely affect the MLP Entities. Adverse decisions by the FERC in approving any of the MLP Entities’ regulated rates could adversely affect their cash flow.

In July 2004, the D.C. Circuit issued its opinion in BP West Coast Products, LLC v. FERC, which upheld, among other things, the FERC’s determination that certain rates of an interstate petroleum products pipeline, Santa Fe Pacific Pipeline (“SFPP”), were grandfathered rates under the Energy Policy Act of 1992 and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification to those rates. The Court also vacated the portion of the FERC’s decision applying the Lakehead policy. In the Lakehead decision, the FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In 2005, the FERC issued a statement of general policy, as well as an order on remand of BP West Coast, in which the FERC stated it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their 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. Although the new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement.

In December 2005, the FERC concluded that for tax allowance purposes, the FERC would apply a rebuttable presumption that corporate partners of pass-through entities pay the maximum marginal tax rate of 35% and that non-corporate partners of pass-through entities pay a marginal rate of 28%. The FERC indicated that it would address the income tax allowance issues further in the context of SFPP’s compliance filing submitted in March 2006. In December 2006, the FERC ruled on some of the issues raised as to the March 2006 SFPP compliance filing, upholding most of its determinations in the December 2005 order. However, the FERC did revise its rebuttable presumption as to corporate partners’ marginal tax rate from 35% to 34%. The FERC’s BP West Coast remand decision and the tax allowance policy were appealed to the D.C. Circuit and certain parties requested a rehearing of the December 2005 order with the FERC.

In May 2007, the D.C. Circuit affirmed FERC’s tax allowance policy. Therefore, the MLP Entities may include in an income tax allowance in their cost of service to the extent they are able to comply with FERC policy. In December 2007, the FERC issued a rehearing order which, among other things, addressed the 2005 order affirming that a pipeline can establish an accrual or potential income tax liability if the partners provide certain information and concluded that the concept of a potential tax liability recognizes that that liability may be deferred and that partners should benefit from tax deferrals. However, 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.

Under the NGA, 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. To be lawful under the NGA, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory, and must be on file with FERC. Existing pipeline rates may be challenged by customer complaint or by the FERC Staff and proposed rate increases may be challenged by protest. The FERC can require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful. Because of the complexity of rate making, the lawfulness of any rate is never assured. A successful challenge of the MLP Entities’ interstate natural gas transportation rates could adversely affect their revenues.

Under the ICA, the STB regulates interstate common carrier propylene pipelines. If the STB finds that a pipeline’s rates are not just and reasonable or are unduly discriminatory or preferential, the STB may prescribe a reasonable rate. In addition, if the STB determines that effective competitive alternatives are

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not available to a shipper and a pipeline holds market power, then Enterprise Products Partners may be required to show that the rates are just and reasonable.

The MLP Entities’ 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. Amounts charged in excess of fair and equitable rates for Section 311 service are subject to refund with interest and the terms and conditions of service, set forth in the pipeline’s Statement of Operating Conditions, are subject to FERC approval. The MLP Entities also have intrastate 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.

The MLP Entities’ intrastate pipelines and natural gas gathering systems are generally exempt from FERC regulation under the NGA, however FERC regulation still significantly affects the natural gas gathering business. In recent years, the FERC has pursued pro-competition policies in its regulation of interstate natural gas pipelines. If the FERC does not continue this approach, it could have an adverse effect on the rates the MLP Entities’ are able to charge in the future. In addition, its natural gas gathering operations could be adversely affected in the future should they become subject to the application of federal regulation of rates and services. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. We cannot predict what effect, if any, such regulatory changes and legislation might have on the MLP Entities’ operations, but they could be required to incur additional capital expenditures.

Enterprise Products Partners has 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. TEPPCO’s new maritime transportation business line is subject to federal regulation under the Jones Act and the Merchant Marine Act of 1936.

ETP’s pipeline operations are subject to ratable take and common purchaser statutes in Texas and Louisiana. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes have the effect of restricting ETP’s right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which ETP operates have adopted complaint-based or other limited economic regulation of natural gas gathering activities which generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access. Other state and local regulations also affect ETP’s business.

ETP’s and Enterprise Products Partners’ intrastate storage facilities are subject to the jurisdiction of the TRRC. Generally, the TRRC has jurisdiction over all underground storage of natural gas in Texas, unless the facility is part of an interstate gas pipeline facility. Because ETP’s ET Fuel System and the Houston Pipeline System natural gas storage facilities are only connected to intrastate gas pipelines, they fall within the TRRC’s jurisdiction and must be operated pursuant to TRRC permit. Certain changes in ownership or operation of TRCC–jurisdictional storage facilities, such as facility expansions and increases in the maximum operating pressure, must be approved by the TRRC through an amendment to the facility’s existing permit. In addition, the TRRC must approve transfers of the permits. The TRRC’s regulations also require all natural gas storage facilities to be operated to prevent waste, the uncontrolled escape of gas, pollution and danger to life or property. Accordingly, the TRRC requires natural gas storage facilities to implement certain safety, monitoring, reporting and record-keeping measures. Violations of the terms and provisions of a TRRC permit or a TRRC order or regulation can result in the modification, cancellation or suspension of an operating permit and/or civil penalties, injunctive relief, or both. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates the MLP Entities charge for transportation and storage

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services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, the MLP Entities’ business may be adversely affected.

The MLP Entities’ pipeline integrity programs may impose significant costs and liabilities on them.

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. The MLP Entities will continue their pipeline integrity testing programs to assess and maintain the integrity of their pipelines. The results of these tests could cause the MLP Entities to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of their pipelines.

Environmental costs and liabilities and changing environmental regulation, including climate change regulation, could affect the MLP Entities’ financial position, results of operations and cash flows.

The MLP Entities’ 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. Further, the MLP Entities cannot ensure that existing environmental regulations will not be revised or that new regulations, such as regulations designed to reduce emissions of greenhouse gases, will not be adopted or become applicable to the MLP Entities. 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.

Each of the MLP Entities 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 increase some costs of the MLP Entities’ operations, including the handling, manufacture, use, emission or disposal of substances and wastes.

Climate change regulation is one area of potential future environmental law development. Studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” may be contributing to warming of the Earth’s atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases. The U.S. Congress is considering legislation to reduce emissions of greenhouse gases. In addition, at least nine states in the Northeast and five states in the West have developed initiatives to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. The EPA is separately considering whether it will regulate greenhouse gases as “air pollutants” under the existing federal Clean Air Act.

Passage of climate control legislation or other regulatory initiatives by Congress or various states of the U.S. or the adoption of regulations by the EPA or analogous state agencies that regulate or restrict emissions of greenhouse gases, including methane or carbon dioxide in areas in which the MLP Entities conduct business, could result in changes to the consumption and demand for natural gas and could have adverse effects on their business, financial position, results of operations and prospects. These changes could increase the MLP Entities’ costs of operations, including costs to operate and maintain facilities,

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install new emission controls on facilities, acquire allowances to authorize greenhouse gas emissions, pay any taxes related to greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While the MLP Entities may be able to include some or all of such increased costs in the rates charged by their pipelines or other facilities, such recovery of costs is uncertain and may depend on events beyond their control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation.

The MLP Entities are subject to strict regulations at many of their facilities regarding employee safety, and failure to comply with these regulations could adversely affect their ability to make distributions to us and the Controlled GP Entities.

The workplaces associated with the MLP Entities’ 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 each MLP Entity maintains information about hazardous materials used or produced in its operations and that it 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 the MLP Entities’ business, financial position, results of operations and ability to make distributions to us and the Controlled GP Entities.

An impairment of goodwill and intangible assets could reduce the MLP Entities’ net income.

At December 31, 2008, Enterprise Products Partners’ balance sheet reflected $706.9 million of goodwill and $855.4 million of intangible assets. At December 31, 2008, TEPPCO’s balance sheet reflected $106.6 million of goodwill and $207.7 million of intangible assets. At December 31, 2008, Energy Transfer Equity’s balance sheet reflected $773.3 million of goodwill and $403.0 million of intangible assets. Additionally, we have recorded $197.6 million of goodwill and $606.9 million of indefinite-lived intangible assets related to the Parent Company’s investment in TEPPCO.

Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires the MLP Entities to test goodwill and indefinite-lived intangible assets 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 any of the MLP Entities determines that any of its goodwill or intangible assets were impaired, it 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.

The MLP Entities may be unable to cause their joint ventures to take or not to take certain actions unless some or all of the joint venture participants agree.

The MLP Entities participate in several joint ventures. Due to the nature of some of these arrangements, the participants have made substantial investments and, accordingly, have 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, the affected MLP Entity may be unable to cause any of its joint ventures to take or not to take certain actions, even though those actions may be in the best interest of the affected MLP Entity or the particular joint venture.

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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 the affected MLP Entity being required to partner with different or additional parties.

Terrorist attacks aimed at any of the MLP Entities’ facilities could adversely affect their business, financial position, results of operations and cash flows.

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 the MLP Entities’ facilities or pipelines or those of their customers could have a material adverse effect on their business.

Risks Relating to Energy Transfer Equity and ETP

The following risks are specific to Energy Transfer Equity and ETP. The following summaries are derived from the risk factors presented by Energy Transfer Equity in its filings with the SEC. We do not control Energy Transfer Equity or ETP, and accordingly rely in large part on information, including risk factors, provided by Energy Transfer Equity in identifying and describing the risks set forth below.

A reduction in ETP’s distributions will disproportionately affect the amount of cash distributions to which Energy Transfer Equity and we are entitled.

Energy Transfer Equity’s direct and indirect ownership of 100% of the IDRs in ETP (50% prior to November 1, 2006), through its ownership of equity interests in the general partner of ETP, the holder of the IDRs, entitles Energy Transfer Equity to receive its pro rata share of specified percentages of total cash distributions made by ETP as it reaches established target cash distribution levels. The amount of the cash distributions that Energy Transfer Equity received from ETP during its fiscal year 2006 related to its ownership interest in the IDRs has increased at a more rapid rate than the amount of the cash distributions related to its 2% general partner interest in ETP and its common units of ETP. Energy Transfer Equity currently receives its pro rata share of cash distributions from ETP based on the highest incremental percentage, 48%, to which the general partner of ETP is entitled pursuant to its IDRs in ETP. A decrease in the amount of distributions by ETP to less than $0.4125 per ETP common unit per quarter would reduce the general partner of ETP’s percentage of the incremental cash distributions above $0.3175 per common unit per quarter from 48% to 23%. As a result, any such reduction in quarterly cash distributions from ETP would have the effect of disproportionately reducing the amount of all distributions that Energy Transfer Equity receives from ETP based on our ownership interest in the IDRs in ETP as compared to cash distributions Energy Transfer Equity receives from ETP on its 2% general partner interest in ETP and its ETP common units. Any such reduction would reduce the amounts that Energy Transfer Equity could distribute to us directly and indirectly through our equity interests in its general partner.

ETP is under investigation by the FERC and CFTC relating to certain trading and transportation activities, and is a party to certain other commodity-based litigation.

ETP is under investigation by the FERC and Commodity Futures Trading Commission (“CFTC”) with respect to whether ETP engaged in manipulation or improper trading activities in the Houston Ship Channel market around the times of the hurricanes in the fall of 2005 and other prior periods in order to benefit financially from its commodities derivative positions and from certain of our index-priced physical gas purchases in the Houston Ship Channel market. The FERC is also investigating certain of ETP’s intrastate transportation activities. In addition, third parties have asserted claims and may assert additional claims for damages related to these matters.

A consolidated class action complaint alleging, among other things, manipulation of natural gas index prices has been filed against ETP. For additional information regarding the above actions, see “Commitments and Contingencies – Litigations” in Note 20 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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At this time, ETP is unable to predict the outcome of these matters; however, it is possible that the amount it becomes obligated to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of existing accrual related to these matters.

As of December 31, 2008, ETP’s accrued amounts for all of its contingencies and current litigation matters (excluding environmental matters) was $20.8 million. Since ETP’s accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from cash from operations or borrowings, which payments would reduce its cash available for distributions either directly or as a result of increased principal and interest payments necessary to service any borrowings incurred to finance such payments. If these payments are substantial, ETP and, ultimately, our investee, Energy Transfer Equity, may experience a material adverse impact on results of operations, cash available for distribution and liquidity.

Tax Risks to Our 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 unitholders would be substantially reduced.

The anticipated after-tax benefit of an investment in our 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 IRS (“Internal Revenue Service”) on this matter. The value of our investment in the MLP Entities depends largely on each of the MLP Entities being treated as a partnership for federal income tax purposes.

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, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our Units.

If any of the MLP Entities were treated as a corporation for federal income tax purposes, it would pay federal income tax on its taxable income at the corporate tax rate. Distributions to us would generally be taxed again as corporate distributions, and no income, gains, losses, deduction or credits would flow through to us. As a result, there would be a material reduction in our anticipated cash flow, likely causing a substantial reduction in the value of our Units.

Current law may change, causing us or any of the MLP Entities to be treated as a corporation for federal income tax purposes or otherwise subjecting us or any of the MLP Entities to a material amount of entity level taxation. In addition, because of widespread state budget deficits and other reasons, several states (including Texas) are evaluating ways to enhance state-tax collections. For example, our operating subsidiaries are subject to the Revised Texas Franchise Tax, on the portion of their revenue that is generated in Texas beginning for tax reports due on or after January 1, 2008. Specifically, the 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 the MLP Entities as an entity, the cash available for distribution to our unitholders would be reduced.

The tax treatment of publicly traded partnerships or an investment in our 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 and the MLP Entities, or an investment in our Units may be modified by administrative, legislative or judicial

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interpretation at any time. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and 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 Units. For example, in response to certain recent developments, members of Congress are considering substantive changes to the definition of qualifying income under Section 7704(d) of the Internal Revenue Code. It is possible that these legislative efforts could result in changes to the existing U.S. tax laws that affect publicly traded partnerships, including us and the MLP Entities. 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 Units.

If the IRS contests the federal income tax positions we take, the market for our Units may be adversely impacted, and the costs of any contest will be borne by our unitholders and EPE Holdings.

The IRS may adopt positions that differ from the position 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 our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely impact the market for our Units and the price at which they trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner.

A successful IRS contest of the federal income tax positions taken by any of the MLP Entities may adversely impact the market for its common units, and the costs of any contest will be borne by such MLP Entity, and therefore indirectly by us and the other unitholders of the MLP Entities.

The IRS may adopt positions that differ from the positions each of the MLP Entities takes, even positions taken with the advice of counsel. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions such MLP Entity takes. A court may not agree with all of the positions such MLP Entity takes. Any contest with the IRS may materially and adversely impact the market for the MLP Entities’ common units and the prices at which the common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees will be borne by the MLP Entities and therefore indirectly by us, as a unitholder of such MLP Entity, and by the other unitholders of the MLP Entities.

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

Our 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 cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from their share of our taxable income.

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

If our unitholders sell their Units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those Units. Prior distributions in excess of the total net taxable income allocated to a unitholder for a Unit, which decreased his tax basis in that Unit, will, in effect, become taxable income if the Unit is sold at a price greater than such unitholder’s tax basis in that Unit, even if the price received is less than such unitholder’s original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to our unitholders.

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Tax-exempt entities and non-U.S. persons face unique tax issues from owning Units that may result in adverse tax consequences to them.

Investment in 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 organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our 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 Units.

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

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of the Units each month based upon the ownership of the 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 amount our unitholders.

The publicly traded partnerships in which we own interests have adopted certain methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders of these publicly traded partnerships. The Internal Revenue Service may challenge this treatment, which could adversely affect the value of the units of a publicly traded partnership in which we own interests and our Units.

When we, or an MLP Entity, issue additional equity securities or engage in certain other transactions, the applicable MLP Entity determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of the MLP Entity’s public unitholders and the MLP Entity’s general partner. This methodology may be viewed as understating the value of the applicable MLP Entity’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner of the MLP Entity, which may be unfavorable to such unitholders. Moreover, under this methodology, subsequent purchasers of our units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to an MLP Entity’s intangible assets and a lesser portion allocated to an MLP Entity’s tangible assets. The Internal Revenue Service may challenge these methods, or our or an MLP Entity’s allocation of income, gain, loss and deduction between the general partner of the MLP Entity and certain of the MLP Entity’s public unitholders.

A successful Internal Revenue Service challenge to these methods or allocations could adversely affect the amount of gain on the sale of units by our unitholders or an MLP Entity’s unitholders and could have a negative impact on the value of our units or those of an MLP Entity or result in audit adjustments to the tax returns of our or an MLP Entity’s unitholders without the benefit of additional deductions.

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Our 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 investing in our Units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we or each of the MLP Entities do business or own property. Our 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, our unitholders may be subject to penalties for failure to comply with those requirements. We or the MLP Entities may own property or conduct business in other states or foreign countries in the future. It is our unitholders’ responsibility 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.

Item 1B. Unresolved Staff Comments.

None.

Item 3. Legal Proceedings.

In February 2008, Joel A. Gerber, a purported unitholder of the Parent Company, filed a derivative complaint on behalf of the Parent Company in the Court of Chancery of the State of Delaware. The complaint names as defendants EPE Holdings; the Board of Directors of EPE Holdings; EPCO; and Dan L. Duncan and certain of his affiliates. The Parent Company is named as a nominal defendant. The complaint alleges that the defendants, in breach of their fiduciary duties to the Parent Company and its unitholders, caused the Parent Company to purchase in May 2007 the TEPPCO GP membership interests and TEPPCO common units from Mr. Duncan’s affiliates at an unfair price. The complaint also alleges that Charles E. McMahen, Edwin E. Smith and Thurmon Andress, constituting the three members of EPE Holdings’ ACG Committee, cannot be considered independent because of their relationships with Mr. Duncan. The complaint seeks relief (i) awarding damages for profits allegedly obtained by the defendants as a result of the alleged wrongdoings in the complaint and (ii) awarding plaintiff costs of the action, including fees and expenses of his attorneys and experts. Management believes this lawsuit is without merit and intends to vigorously defend against it. For information regarding our relationship with Mr. Duncan and his affiliates, see Note 17 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Information regarding significant legal proceedings affecting Enterprise Products Partners, TEPPCO or Energy Transfer Equity is presented under “Commitments and Contingencies – Litigation” in Note 20 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. Such information is incorporated by reference into this Item 3.

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

None.

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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 Units are listed on the NYSE under the ticker symbol “EPE.” As of February 2, 2009, there were approximately 50 unitholders of record of our Units. The following table presents the high and low sales prices for our 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 Units with respect to such periods.

			Cash Distribution History
	Price Ranges		Per	Record	Payment
	High	Low	Unit	Date	Date
2007
1st Quarter	$40.100	$34.700	$ 0.365	Apr. 30, 2007	May 11, 2007
2nd Quarter	$41.880	$36.330	$ 0.380	Jul. 31, 2007	Aug. 10, 2007
3rd Quarter	$46.960	$32.760	$ 0.395	Oct. 31, 2007	Nov. 9, 2007
4th Quarter	$37.750	$32.850	$ 0.410	Jan. 31, 2008	Feb. 8, 2008
2008
1st Quarter	$36.86	$27.86	$0.4250	Apr. 30, 2008	May 8, 2008
2nd Quarter	$33.76	$29.51	$0.4400	Jul. 31, 2008	Aug. 8, 2008
3rd Quarter	$30.64	$21.16	$0.4550	Oct. 31, 2008	Nov. 13, 2008
4th Quarter	$24.20	$14.50	$0.4700	Jan. 30, 2009	Feb. 10, 2009

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 unitholders) occur within 50 days after the end of such quarter. We expect to fund our quarterly cash distributions to our unitholders 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 securities in 2008. See Note 16 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding our Units.

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

None.

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Item 6. Selected Financial Data.

The following table presents selected historical consolidated financial data for the Partnership. Information presented with respect to the years ended December 31, 2008, 2007 and 2006 and at December 31, 2008 and 2007 should be read in conjunction with the audited financial statements included under Item 8 of this annual report. The operating results and balance sheet information for periods prior to our initial public offering in April 2005 were derived from the consolidated financial information of our predecessor, EPGP and its subsidiaries, which includes Enterprise Products Partners. 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,
	2008		2007		2006		2005		2004
Results of operations data: (1)
Revenues	$	35,469,576	$	26,713,769	$	23,612,146	$	20,858,240	$	8,321,202
Income from continuing operations (2)	$	164,055	$	109,021	$	133,899	$	82,436	$	29,562
Basic and diluted net income per unit (3)	$	1.33	$	0.97	$	1.30	$	0.90	$	0.40
Other financial data:
Distributions per unit (4)	$	1.79	$	1.55	$	1.29	$	0.372		n/a

	At December 31,
	2008		2007		2006		2005		2004
Financial position data: (1)
Total assets	$	25,371,346	$	23,724,102	$	18,699,891	$	17,074,071	$	11,315,901
Long-term and current maturities of debt (5)	$	12,714,928	$	9,861,205	$	7,053,877	$	6,493,301	$	4,647,669
Partners’ equity (6)	$	1,845,303	$	2,039,022	$	1,440,249	$	1,469,606	$	74,045
Total Units outstanding (7)		123,192		112,325		103,057		91,802		74,667

(1) In general, our historical results of operations and financial position have been affected by business combinations, asset acquisitions and other capital spending, including the consolidation of TEPPCO effective January 1, 2005. In February 2005, private company affiliates of EPCO under common control with the Parent Company acquired ownership interests in TEPPCO and TEPPCO GP. In May 2007, the Parent Company acquired non-controlling interests in both Energy Transfer Equity and LE GP. (2) Amounts presented are before the cumulative effect of changes in accounting principles. (3) For information regarding our earnings per unit for the years ended December 31, 2008, 2007 and 2006, see Note 19 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. (4) For information regarding the Parent Company’s cash distributions, see Note 16 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. (5) In general, our consolidated debt has increased over time as a result of financing all or a portion of acquisitions and other capital spending. In addition, the inclusion of TEPPCO effective January 1, 2005 increased our consolidated debt. (6) For information regarding our partners’ equity, see Note 16 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. (7) Represents the weighted-average number of Units outstanding during each year. For additional information regarding Units outstanding, see Note 19 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, 2008, 2007 and 2006.

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.

§	Basis of Presentation.

§	General Outlook for 2009.

§	Parent Company Recent Developments – Discusses significant matters pertaining to the Parent Company during the year ended December 31, 2008.

§	Results of Operations – Discusses material year-to-year changes in operating income, interest expense, other income and minority interest as presented in our Statements of Consolidated Operations.

§	Liquidity and Capital Resources – Addresses available sources of liquidity and capital resources and includes a discussion of our consolidated 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 other matters.

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
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 management’s discussion and analysis contains various forward-looking statements and information that are based on our beliefs and those of EPE Holdings, 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,” “estimate,” “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 EPE Holdings believe that such expectations reflected in such forward-looking statements are reasonable, neither we nor EPE Holdings can give any assurances that such expectations will prove to be correct.

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Such statements are subject to a variety of risks, uncertainties and assumptions as described in more detail in Item 1A of this annual report. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. You should not put undue reliance on any forward-looking statements.

Significant Relationships Referenced in this Discussion and Analysis

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Overview of Business

We are a publicly traded Delaware limited partnership, the limited partnership interests (the “Units”) of which are listed on the NYSE under the ticker symbol “EPE.” The business of Enterprise GP Holdings L.P. is the ownership of general and limited partner interests of publicly traded partnerships engaged in the midstream energy industry and related businesses to increase cash distributions to its unitholders.

The Parent Company is owned 99.99% by its limited partners and 0.01% by its general partner, EPE Holdings. EPE Holdings is a wholly owned subsidiary of Dan Duncan, LLC, the membership interests of which are owned by Dan L. Duncan. The Parent Company has no operations apart from its investing activities and indirectly overseeing the management of the entities controlled by it. At December 31, 2008 the Parent Company had investments in Enterprise Products Partners, TEPPCO, Energy Transfer Equity and their respective general partners.

See Note 24 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for financial information regarding the Parent Company.

Basis of Presentation

In accordance with rules and regulations of the U.S. Securities and Exchange Commission (“SEC”) and various other accounting standard-setting organizations, our general purpose financial statements reflect the consolidation of the financial statements of businesses that we control through the ownership of general partner interests (e.g. Enterprise Products Partners and TEPPCO). Our general purpose consolidated financial statements present those investments in which we do not have a controlling interest as unconsolidated affiliates (e.g. Energy Transfer Equity and LE GP). To the extent that Enterprise Products Partners and TEPPCO reflect investments in unconsolidated affiliates in their respective consolidated financial statements, such investments will also be reflected as such in our general purpose financial statements unless subsequently consolidated by us due to common control considerations (e.g. Jonah Gas Gathering Company and the Texas Offshore Port System). Also, minority interest presented in our financial statements reflects third-party and related party ownership of our consolidated subsidiaries, which include the third-party and related party unitholders of Enterprise Products Partners, TEPPCO and Duncan Energy Partners other than the Parent Company. Unless noted otherwise, our discussions and analysis in this annual report are presented from the perspective of our consolidated businesses and operations.

General Outlook for 2009

Enterprise Products Partners and TEPPCO

The current global recession and financial crisis have impacted energy companies generally. The recession and related slowdown in economic activity has reduced demand for energy and related products, which in turn has generally led to significant decreases in the prices of crude oil, natural gas and NGLs. The financial crisis has resulted in the effective insolvency, liquidation or government intervention for a number of financial institutions, investment companies, hedge funds and highly leveraged industrial companies. This has had an adverse impact on the prices of debt and equity securities that has generally increased the cost and limited the availability of debt and equity capital.

Commercial Outlook. In 2008, there was significant volatility in the prices of refined products, crude oil, natural gas, LPGs and NGLs. For example, the price of West Texas Intermediate crude oil ranged from a high near $147 per barrel in mid-2008 to $35 per barrel in January 2009; while the price of natural gas at the Henry Hub ranged from a high of over $13.00 per MMBtu in mid-2008 to $5.00 per MMBtu in January 2009. On a composite basis, the average price of NGLs declined from $1.68 per gallon for the third quarter of 2008 to $0.74 per gallon for the fourth quarter of 2008. The decrease in energy commodity prices combined with higher costs of capital have led many crude oil and natural gas producers to reconsider their drilling budgets for 2009. As midstream energy companies, Enterprise Products

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Partners and TEPPCO provide services for producers and consumers of natural gas, NGLs, crude oil and certain petrochemicals. The products that they 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.

The decrease in energy commodity prices has caused many oil and natural gas producers, which include many customers of Enterprise Products Partners, TEPPCO and ETP, to reduce their drilling budgets in 2009. This has resulted in a substantial reduction in the number of drilling rigs operating in the United States as surveyed by Baker Hughes Incorporated. The U.S. operating rig count decreased from a peak of 2,031 rigs in September 2008 to approximately 1,300 in February 2009. We expect oil and gas producers in our operating areas to reduce their drilling activity to varying degrees, which may lead to lower crude oil, natural gas and NGL production growth in the near term and, as a result, lower transportation, processing and marketing volumes for Enterprise Products Partners and TEPPCO than would have otherwise been the case.

In its natural gas processing business, Enterprise Products Partners hedged approximately 80% of its equity NGL production margins for 2008 to mitigate the commodity price risk associated with these volumes. It has hedged approximately 67% of its expected equity NGL production margins for 2009. Since the hedges were consummated at prices that are significantly higher than current levels, Enterprise Products Partners is expected to be partially insulated from lower natural gas processing margins in 2009.

The recession has reduced demand for midstream energy services and products by industrial customers. In the fourth quarter of 2008, the petrochemical industry experienced a dramatic destocking of inventories, which reduced demand for purity NGL products such as ethane, propane and normal butane. We expect that petrochemical demand will strengthen in early 2009 and have starting seeing signs of such demand through February 2009 as petrochemical customers have begun to restock their depleted inventories. This trend is also evidenced by slightly higher operating rates of U.S. ethylene crackers, which averaged approximately 70% of capacity in February 2009 as compared to 56% in December 2008. Four additional ethylene crackers were expected to recommence operations in February 2009. The average utilization rate for ethylene crackers in 2008 was approximately 80%. Based on currently available information, we expect that the operating rates of U.S. ethylene crackers will approximate 80% of capacity in 2009. We expect that crude oil prices will rebound from recent lows in the second half of 2009. As a result, we believe the petrochemical industry will continue to prefer NGL feedstocks over crude-based alternatives such as naphtha. In general, when the price of crude oil rises relative to that of natural gas, NGLs become more attractive as a source of feedstocks for the petrochemical industry.

The recession has also impacted the demand for refined products such as gasoline, diesel and jet fuel. According to EIA statistics, gasoline demand decreased 3.5% for 2008 when compared to 2007. Demand for diesel and jet fuel have also weakened in response to the slowing economy. Many refiners have announced plans to perform major maintenance projects during the first quarter of 2009 in response to weakened demand for their products. This situation will most likely contribute to a decrease in transportation volumes on refined products pipelines such as those owned by TEPPCO. We expect that demand for refined products will remain at current levels until the domestic economy begins to recover from the current recession.

The reduction in near-term demand for crude oil and NGLs has created a contango market (i.e., a market in which the price of a commodity is higher in future months than the current spot price) for these products, which, in turn, we are benefiting from through an increase in revenues earned by our storage assets in Mont Belvieu, Texas and Cushing, Oklahoma.

Liquidity Outlook. Debt and equity capital markets have also experienced significant recent volatility. The major U.S. and international equity market indices experienced significant losses in 2008, including losses of approximately 38% and 34% for the S&P 500 and Dow Jones Industrial Average, respectively. Likewise, the Alerian MLP Index, which is a recognized major index for publicly traded partnerships, lost approximately 42% of its value. The contraction in credit available to and investor redemptions of holdings in certain investment companies and hedge funds exacerbated the selling pressure

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and volatility in both the debt and equity capital markets. This has resulted in a higher cost of debt and equity capital for the public and private sector. Near term demand for equity securities through follow on offerings, including common units of Enterprise Products Partners and TEPPCO, may be reduced due to the recent problems encountered by investment companies and hedge funds, both of which significantly participated in equity offerings over the past few years.

While the cost of capital has increased, Enterprise Products Partners has demonstrated its ability to access the debt and equity capital markets during this distressed period. In December 2008, Enterprise Products Partners issued $500.0 million of 9.75% senior notes. The higher cost of capital is evident when you compare the interest rate of the December 2008 senior notes offering to the $400.0 million of 5.65% senior notes that Enterprise Products Partners issued in March 2008. On a positive note, Enterprise Products Partners’ indicative cost of long-term borrowing has improved approximately 250 basis points in early 2009 in conjunction with the recent improvement in the debt capital markets. Enterprise Products Partners believes that it will be able to either access the capital markets or utilize availability under its long-term multi-year revolving credit facility to refinance its $717.6 million of debt obligations that mature in 2009. In January 2009, Enterprise Products Partners issued approximately 10.6 million of its common units at an effective annual distribution yield of 9.5%. Net proceeds from this offering were $225.6 million and used to reduce borrowings and for general partnership purposes.

TEPPCO’s actions to raise approximately $510.0 million of capital in the third quarter of 2008, including $264.0 million of net proceeds from a September 2008 equity offering and $250.0 million from increasing commitments under its credit facility, put TEPPCO in position to avoid the higher cost of debt and equity capital that prevailed in the fourth quarter of 2008.

The increase in the cost of capital has caused Enterprise Products Partners and TEPPCO to prioritize their respective internal growth projects to select those with higher rates of return. However, consistent with their business strategies, Enterprise Products Partners and TEPPCO continuously evaluate possible acquisitions of assets that would complement their current operations. Given the current state of the credit markets, Enterprise Products Partners and TEPPCO believe competition for such assets has decreased, which may result in opportunities for them to acquire assets at attractive prices that would be accretive to their partners and expand their portfolio of midstream energy assets.

Based on information currently available, Enterprise Products Partners estimates that its capital spending for property, plant and equipment in 2009 will approximate $1.0 billion, which includes $820.0 million for growth capital projects and $180.0 million for sustaining capital expenditures. TEPPCO estimates that its spending for property, plant and equipment in 2009 will approximate $340.0 million, which includes $288.0 million for growth capital projects and $52.0 million primarily for sustaining capital expenditures. The 2009 forecast amounts for growth capital projects include amounts that are expected to be spent by Enterprise Products Partners and TEPPCO on the Texas Offshore Port System. See “Results of Operations – Investment in Enterprise Products Partners” for additional information regarding the Texas Offshore Port System joint venture.

Enterprise Products Partners expects four of its significant construction projects to be completed and the assets placed into service during the first half of 2009. These projects include (i) the expansion of the Meeker natural gas processing plant, which began operations in February 2009, (ii) the Exxon Mobil central treating facility, (iii) the Sherman Extension natural gas pipeline, and (iv) the Shenzi crude oil pipeline in the Gulf of Mexico. Substantially all of the financing to fund these projects has been completed. In 2009, Enterprise Products Partners expects these projects to contribute significant new sources of revenue, operating income and cash flow from operations.

Hurricanes Gustav and Ike damaged a number of energy-related assets onshore and offshore along the Texas and Louisiana Gulf Coast in the summer of 2008, including certain of Enterprise Products Partners’ offshore pipelines and platforms. Repairs are being completed on Enterprise Products Partners’ affected assets and they are expected to be ready to return to service once third party production fields return to operational status over the course of 2009.

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A few of Enterprise Products Partners’ and TEPPCO’s customers have experienced severe financial problems leading to a significant impact on their creditworthiness. These financial problems are rooted in various factors including the significant use of debt, current financial crises, economic recession and changes in commodity prices. Enterprise Products Partners and TEPPCO are working to implement, to the extent allowable under applicable contracts, tariffs and regulations, prepayments and other security requirements, such as letters of credit, to enhance their respective credit position relating to amounts owed them by certain customers. We cannot provide assurance that one or more of our customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our consolidated financial position, results of operations, or cash flows; however, Enterprise Products Partners and TEPPCO believe that they have provided adequate allowances for such customers.

We expect that Enterprise Products Partners’ and TEPPCO’s proactive approach to funding capital spending and other partnership needs, combined with sufficient trade credit to operate their businesses efficiently, and available borrowing capacity under their credit facilities, will provide them with a foundation to meet their anticipated liquidity and capital requirements in 2009. We believe that Enterprise Products Partners and TEPPCO will be able to access the capital markets in 2009 to maintain financial flexibility. Based on information currently available to us, we believe that Enterprise Product Partners and TEPPCO will maintain their investment grade credit ratings and meet their loan covenant obligations in 2009.

Energy Transfer Equity (as excerpted from Energy Transfer Equity L.P. s Form 10-K

for the fiscal year ended December 31, 2008)

The following information was taken directly from the “Trends and Outlook” section under Item 7 of Energy Transfer Equity, L.P. annual report on Form 10-K for the year ended December 31, 2008. Within the context of the following quotes, references to “we,” “us,” “our,” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP. References to “the Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis. References to “FEP” mean Fayetteville Express Pipeline, LLC. The following statements are the responsibility of the management of Energy Transfer Equity L.P. and we have not made any independent inquiry with respect to such matters.

“The current constraints in the capital markets may affect our ability to obtain funding through new borrowings or the issuance of Common Units. In addition, we expect that, to the extent we are successful in arranging new debt financing, we will incur increased costs associated with these debt financings. In light of the current market conditions, we have taken steps to preserve our liquidity position including, but not limited to, reducing discretionary capital expenditures, maintaining our cash distribution rate and continuing to appropriately manage operating and administrative costs to improve profitability. ETP also successfully completed a $600.0 million senior note offering in December 2008 and a 6.9 million ETP Common Unit offering in January 2009. As of December 31, 2008, in addition to approximately $91.9 million of cash on hand, we had available capacity under the Parent Company’s debt facilities and the ETP Credit Facility of $1.42 billion. On a pro forma basis, as of December 31, 2008, taking into account net proceeds of approximately $225.9 million from ETP’s January 2009 equity offering, available capacity under the ETP Credit Facility was $1.27 billion. We expect to utilize these resources, along with cash from operations, to fund our announced growth capital expenditures for 2009 and working capital needs during 2009. In addition to these sources of liquidity, we may also access the debt and equity markets during 2009 in order to provide additional liquidity to fund growth capital expenditures for future years or for other partnership purposes.

ETP will continue to evaluate a variety of financing sources in order to fund its future growth capital expenditures and working capital needs, including funds available under our existing revolving credit facility, funds raised from future equity and/or debt offerings and funds raised from other sources, which sources may include project financing or other alternative financing arrangements from third parties or affiliated parties. In this regard, ETP has initiated discussions with us regarding the prospect of our purchasing additional ETP Common Units from ETP. We have an aggregate of approximately $378.4 million of cash on hand and available borrowing capacity under our revolving credit facility as of December 31, 2008.

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We believe that the size and scope of our operations, our stable asset base and cash flow profile and our investment grade status will be significant positive factors in our efforts to obtain new debt or equity funding; however, there is no assurance that we will be successful in obtaining financing under any of the alternatives discussed above if current capital market conditions continue for an extended period of time or if markets deteriorate further from current conditions. Furthermore, the terms, size and cost of any one of these financing alternatives could be less favorable and could be impacted by the timing and magnitude of our funding requirements, market conditions, and other uncertainties.

Current economic conditions also indicate that many of our customers may encounter increased credit risk in the near term. In particular, our natural gas transportation and midstream revenues are derived significantly from companies that engage in natural gas exploration and production activities. Prices for natural gas and NGLs have fallen dramatically since July 2008. Many of our customers have been negatively impacted by these recent declines in natural gas prices as well as current conditions in the capital markets, which factors have caused several of our customers to announce plans to decrease drilling levels and, in some cases, to consider shutting in natural gas production from some producing wells.

In our intrastate and interstate natural gas operations, a significant portion of our revenue is derived from long-term fee-based arrangements pursuant to which our customers pay us capacity reservation charges regardless of the volume of natural gas transported; however, a portion of our revenue is derived from charges based on actual volumes transported. As a result, our operating cash flows from our natural gas pipeline operations are not tied directly to changes in natural gas and NGL prices; however, the volumes of natural gas we transport may be adversely affected by reduced drilling activity of our customers as a result of lower natural gas prices. As a portion of our pipeline transportation revenue is based on volumes transported, lower volumes of natural gas transported would result in lower revenue from our intrastate and interstate natural gas operations. Based on the significant level of revenue we receive from reservation capacity charges under long-term contracts and our review of the recent announcements of drilling plans by our customers, we do not expect the current level of natural gas prices to have a significant adverse effect on our operating results; however, there are no assurances that commodity prices will not decline further, which could result in a further reduction in drilling activities by our customers.

Since certain of our natural gas marketing operations and substantially all of our propane operations involve the purchase and resale of natural gas and NGLs, we expect our revenues and costs of products sold to be lower than prior periods if commodity prices remain at or fall below existing levels. However, we do not expect our margins from these activities to be significantly impacted as we typically purchase the commodity at a lower price than the sales price. Since the prices of natural gas and NGLs have been volatile, there are no assurances that we will ultimately sell the commodity for a profit.

As noted above, we may reduce our level of discretionary capital expenditures for growth projects in order to preserve our capital resources in the event that the capital market conditions do not allow us to obtain debt or equity financing on reasonable terms. In the event we do not pursue growth projects due to lack of capital, we would likely not achieve the growth in distributable cash flow as we have previously planned.

We actively monitor the credit status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit default swaps where applicable, and to date have not had any significant credit defaults associated with our transactions. However, given the current volatility in the financial markets, we cannot be certain that we will not experience such losses in the future.”

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Parent Company Recent Developments

The following information highlights the Parent Company’s significant developments since January 1, 2008 through the date of this filing.

Conversion of Class C Units

On February 1, 2009, all of the Parent Company’s 16,000,000 Class C Units converted to Units on a one-to-one basis. These Units are eligible to receive cash distributions beginning with the distribution expected to be paid in May 2009 with respect to the first quarter of 2009. For additional information regarding the Class C Units, see Note 16 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Acquisition of additional interests in LE GP

On January 22, 2009, the Parent Company acquired an additional 5.7% membership interest in LE GP for $0.8 million, which increased our total ownership in LE GP to 40.6%.

Results of Operations

Our investing activities are organized into business segments that reflect how the Chief Executive Officer of our general partner (i.e., our chief operating decision maker) routinely manages and reviews the financial performance of the Parent Company’s investments. On a consolidated basis, we have three reportable business segments:

§	Investment in Enterprise Products Partners – Reflects the consolidated operations of Enterprise Products Partners and its general partner, EPGP. This segment also includes the development stage assets of the Texas Offshore Port System joint venture (as defined below).

In August 2008, Enterprise Products Partners, TEPPCO and Oiltanking, announced the formation of a joint venture (the “Texas Offshore Port System”) to design, construct, operate and own a Texas offshore crude oil port and a related onshore pipeline and storage system that would facilitate delivery of waterborne crude oil cargoes to refining centers located along the upper Texas Gulf Coast. Demand for such projects is being driven by planned and expected refinery expansions along the Gulf Coast, expected increases in shipping traffic and operating limitations of regional ship channels.

The joint venture’s primary project, referred to as “TOPS,” includes (i) an offshore port (which will be located approximately 36 miles from Freeport, Texas), (ii) an onshore storage facility with approximately 3.9 MMBbls of crude oil storage capacity, and (iii) an 85-mile crude oil pipeline system having a transportation capacity of up to 1.8 MMBbls/d, that will extend from the offshore port to a storage facility near Texas City, Texas. The joint venture’s complementary project, referred to as the Port Arthur Crude Oil Express (or “PACE”) will transport crude oil from Texas City, including crude oil from TOPS, and will consist of a 75-mile pipeline and 1.2 MMBbls of crude oil storage capacity in the Port Arthur, Texas area. Development of the TOPS and PACE projects is supported by long-term contracts with affiliates of Motiva and Exxon Mobil, which have committed a combined 725,000 barrels per day of crude oil to the projects. The timing of the construction and related capital costs of the TOPS and PACE projects will be affected by the expansion plans of Motiva and the acquisition of requisite permits.

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$700.0 million, which includes a contingency amount for potential cost overruns, of the capital contribution obligations of their respective subsidiary partners in the joint venture.

Within their respective financial statements, TEPPCO and Enterprise Products Partners will account for their individual ownership interests in the Texas Offshore Port System using the equity method of accounting. As a result of common control of TEPPCO and Enterprise Products Partners at the Parent Company level, the Texas Offshore Port System is a consolidated subsidiary of the Parent Company and Oiltanking’s interest in the joint venture is accounted for as minority interest. For financial reporting purposes, our management determined that the joint venture should be included within the Investment in Enterprise Products Partners segment.

§	Investment in TEPPCO – Reflects the consolidated operations of TEPPCO and its general partner, TEPPCO GP. This segment also includes the assets and operations of Jonah Gas Gathering Company (“Jonah”).

§	Investment in Energy Transfer Equity – Reflects the Parent Company’s investments in Energy Transfer Equity and its general partner, LE GP. These investments were acquired in May 2007. The Parent Company accounts for these non-controlling investments using the equity method of accounting.

We evaluate segment performance based on operating income. For additional information regarding our business segments, see Note 4 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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The following table summarizes our historical financial information by business segment for the periods indicated (dollars in thousands):

	For the Year Ended December 31,
	2008			2007			2006
Revenues:
Investment in Enterprise Products Partners	$	21,905,656		$	16,950,125		$	13,990,969
Investment in TEPPCO		13,765,905			9,862,676			9,691,320
Eliminations (1)		(201,985	)		(99,032	)		(70,143	)
Total revenues		35,469,576			26,713,769			23,612,146
Costs and expenses:
Investment in Enterprise Products Partners		20,551,874			16,097,178			13,154,755
Investment in TEPPCO		13,398,579			9,520,610			9,425,153
Other, non-segment including Parent Company (2)		(189,803	)		(84,241	)		(59,569	)
Total costs and expenses		33,760,650			25,533,547			22,520,339
Equity earnings (loss):
Investment in Enterprise Products Partners		37,734			20,301			21,327
Investment in TEPPCO		(2,871	)		(9,793	)		3,886
Investment in Energy Transfer Equity (3)		31,298			3,095			--
Total equity earnings		66,161			13,603			25,213
Operating income:
Investment in Enterprise Products Partners		1,391,516			873,248			857,541
Investment in TEPPCO		364,455			332,273			270,053
Investment in Energy Transfer Equity		31,298			3,095			--
Other, non-segment including Parent Company		(12,182	)		(14,791	)		(10,574	)
Total operating income		1,775,087			1,193,825			1,117,020
Interest expense		(608,223	)		(487,419	)		(333,742	)
Provision for income taxes		(31,019	)		(15,813	)		(21,974	)
Other income, net		9,668			71,788			11,180
Income before minority interest and cumulative
effect of change in accounting principle		1,145,513			762,381			772,484
Minority interest (4)		(981,458	)		(653,360	)		(638,585	)
Cumulative effect of change in accounting principle (5)		--			--			93
Net income	$	164,055		$	109,021		$	133,992

(1) Represents the elimination of revenues between our business segments. (2) Represents the elimination of expenses between business segments. In addition, these amounts include nominal amounts of general and administrative costs of the Parent Company. Such costs were $7.3 million, $4.3 million and $2.1 million for the years ended December 31, 2008, 2007 and 2006, respectively. (3) Represents equity earnings from the Parent Company’s investments in Energy Transfer Equity and LE GP. See Note 12 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding these investments, including related excess cost amortization. (4) Minority interest represents the allocation of earnings of our consolidated subsidiaries to third party and related party owners of such entities other than the Parent Company. See Note 2 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding our minority interest amounts. (5) For information regarding the change in accounting principle, including a presentation of the pro forma effects these changes would have on our historical earnings, see Note 9 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Review of Segment Operating Income Amounts

Comparison of 2008 with 2007

Investment in Enterprise Products Partners. Segment revenues increased $4.96 billion year-to-year primarily due to higher energy commodity sales volumes and prices associated with Enterprise Products Partners’ marketing activities. These factors contributed to a $5.01 billion year-to-year increase in segment revenues associated with Enterprise Products Partners’ marketing activities. Equity NGLs produced at Enterprise Products Partners’ newly constructed Meeker and Pioneer natural gas plants and

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sold in connection with Enterprise Products Partners’ NGL marketing activities contributed $731.3 million of the year-to-year increase in marketing activity revenues.

Segment costs and expenses, which include operating expenses and general and administrative costs, increased $4.45 billion year-to-year. The cost of sales associated with Enterprise Products Partners’ marketing activities increased $3.57 billion year-to-year primarily due to higher energy commodity sales volumes and prices. The remainder of the year-to-year increase in segment operating costs and expenses is attributable to (i) a $306.3 million year-to-year increase in operating expenses associated with Enterprise Products Partners’ natural gas processing plants as a result of higher energy commodity prices and (ii) a $414.3 million year-to-year increase in operating costs and expenses attributable to Enterprise Products Partners’ newly constructed assets. Segment general and administrative costs increased $2.8 million year-to-year.

Changes in Enterprise Products Partners’ 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 $1.40 per gallon during 2008 versus $1.19 per gallon during 2007. 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, Texas, which is the primary industry hub for domestic NGL production. The market price of natural gas (as measured at Henry Hub) averaged $9.04 per MMBtu during 2008 versus $6.86 per MMBtu during 2007.

Total segment operating income increased $518.3 million year-to-year due to strength in the underlying performance of Enterprise Products Partners’ business lines. Enterprise Products Partners operates in four primary business lines: NGL Pipelines & Services, Onshore Natural Gas Pipelines & Services, Offshore Pipelines & Services and Petrochemical Services.

Operating income attributable to NGL Pipelines & Services increased $438.9 million year-to-year primarily due to strong natural gas processing margins and demand for NGLs from the petrochemical and motor gasoline refining industries during 2008. These factors lead to higher NGL sales margins during 2008 relative to 2007. In addition, these factors also resulted in a year-to-year increase in equity NGL production and higher NGL throughput volumes at certain of Enterprise Products Partners’ pipelines and fractionation facilities.

Operating income attributable to Onshore Natural Gas Pipelines & Services increased $68.9 million year-to-year primarily due to higher revenues from Enterprise Products Partners’ San Juan Gathering System and increased transportation volumes and fees on its Texas Intrastate System. This business line also benefited from higher natural gas volumes on certain of Enterprise Products Partners’ other pipelines and storage assets as well as higher natural gas sales margins on its Acadian Gas System.

Operating income attributable to Offshore Pipelines & Services increased $13.6 million year-to-year primarily due to increased volumes on Enterprise Products Partners’ Independence Hub platform and Trail pipeline and its Cameron Highway Oil Pipeline. Contributions to operating income from these assets were largely offset by the effects of Hurricanes Gustav and Ike, which include (i) downtime resulting from damage sustained by Enterprise Products Partners’ offshore assets as well as downstream assets owned by third-parties, (ii) reduced volumes available to Enterprise Products Partners’ offshore assets as a result of upstream supply disruptions and (iii) property damage repair expenses.

Operating income attributable to Petrochemical Services decreased $3.2 million year-to-year. A decrease in operating income from Enterprise Products Partners’ octane enhancement business attributable to the effects of operational issues and Hurricane Ike during 2008 was partially offset by an increase in operating income from Enterprise Products Partners’ propylene fractionation business. Enterprise Products Partners’ propylene fractionation business benefited from a year-to-year increase in propylene sales margins.

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As a result of Enterprise Products Partners’ allocated share of EPCO’s insurance deductibles for windstorm coverage, segment operating income for 2008 includes $47.9 million of repair expenses for property damage sustained by Enterprise Products Partners’ assets as a result of Hurricanes Gustav and Ike.

Investment in TEPPCO. Segment revenues increased $3.90 billion year-to-year primarily due to higher crude oil prices and petroleum products sales volumes during 2008 relative to 2007. These factors contributed to a $3.66 billion increase in segment revenues associated with TEPPCO’s marketing activities, primarily crude oil sales. TEPPCO’s Marine Services business line, which TEPPCO acquired in February 2008, contributed $164.3 million of revenues during 2008.

Segment costs and expenses, which include operating expenses and general and administrative costs, increased $3.88 billion year-to-year. The cost of sales associated with TEPPCO’s marketing activities increased $3.66 billion year-to-year as a result of higher crude oil prices and sales volumes. TEPPCO’s Marine Services business line accounted for $129.8 million of costs and expenses during 2008. The remainder of the year-to-year increase in segment costs and expenses is primarily attributable to higher pipeline operating and maintenance expenses. Segment general and administrative costs increased $7.0 million year-to-year largely due to expenses associated with the Marine Services business line.

Changes in TEPPCO’s revenues and costs and expenses year-to-year are explained in part by changes in energy commodity prices. The market price of crude oil (as measured on the New York Mercantile Exchange (“NYMEX”)) averaged $99.73 per barrel during 2008 compared to an average of $72.24 per barrel during 2007 – a 38% increase.

Segment operating income increased $32.2 million year-to-year primarily due to the underlying results of TEPPCO’s four primary business lines: Downstream, Upstream, Midstream and Marine Services. Segment operating income for 2008 included $34.5 million attributable to TEPPCO’s Marine Services business line.

Operating income attributable to the Upstream business line increased $20.6 million year-to-year primarily due to higher pipeline throughput volumes. Operating income attributable to the Midstream business line increased $22.9 million year-to-year primarily due to higher volumes on the Jonah system attributable to the completion of the Phase V expansion project. Capacity on the Jonah system to gather natural gas from the Jonah and Pinedale fields increased to 2.35 Bcf/d from 1.5 Bcf/d as a result of the Phase V expansion project. Operating income attributable to the Downstream business line decreased $46.3 million year-to-year primarily due to expenses associated with pipeline and storage tank maintenance, inventory adjustments during 2008 and a gain that TEPPCO recorded in connection with its sale of assets to a third-party in March 2007.

As a result of TEPPCO’s allocated share of EPCO’s insurance deductibles for windstorm coverage, segment operating income for 2008 includes $1.2 million of repair expenses for property damage sustained by TEPPCO’s assets as a result of Hurricane Ike.

Investment in Energy Transfer Equity. Segment operating income was $31.3 million for 2008 versus $3.1 million for 2007. This segment reflects the Parent Company’s non-controlling ownership interests in Energy Transfer Equity and its general partner, LE GP, both of which are accounted for using the equity method. Total segment operating income increased $28.2 million year-to-year primarily as a result of our acquisition of interests in Energy Transfer Equity and LE GP in May 2007. In May 2007, the Parent Company paid $1.65 billion to acquire approximately 17.5% of the common units of Energy Transfer Equity, or 38,976,090 units, and approximately 34.9% of the membership interests of LE GP.

Equity earnings from these investments are derived from financial statements published in the SEC filings of Energy Transfer Equity. Our equity earnings from these investments were reduced by $34.3 million and $26.7 million of excess cost amortization during 2008 and 2007, respectively. For additional information regarding our investments in Energy Transfer Equity and LE GP, see Note 12 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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According to Energy Transfer Equity, it completed several significant intrastate pipeline projects in 2008 that contributed to its operating income, which was $1.10 billion for the year ended December 31, 2008 versus $809.3 million for the fiscal year ended August 31, 2007. In addition, Energy Transfer Equity experienced increased volumes in its natural gas operations and better than expected processing margins throughout most of 2008. The year-to-year increase in Energy Transfer Equity’s operating income was partially offset by losses on interest rate hedging derivatives and higher interest expense and minority interest amounts. On a consolidated basis, Energy Transfer Equity incurred losses on non-hedged interest rate derivatives of $128.4 million during the year ended December 31, 2008 compared to gains of $29.1 million during the fiscal year ended August 31, 2007.

In November 2007, Energy Transfer Equity changed its fiscal year end to the calendar year end; thus, its current fiscal year began on January 1, 2008. Energy Transfer Equity did not recast its consolidated financial data for prior fiscal periods. According to Energy Transfer Equity, comparability between periods is impacted primarily by weather, fluctuations in commodity prices, volumes of natural gas sold and transported, its hedging strategies and use of financial instruments, trading activities, basis differences between market hubs and interest rates. Energy Transfer Equity believes that the trends indicated by comparison of the results for the calendar year ended December 31, 2008 are substantially similar to what is reflected in the information for the fiscal year ended August 31, 2007.

Comparison of 2007 with 2006

Investment in Enterprise Products Partners. Segment revenues increased $2.96 billion year-to-year primarily due to higher energy commodity sales volumes and prices during 2007 relative to 2006. Revenues for 2007 include $36.1 million of proceeds from business interruption insurance claims compared to $63.9 million of proceeds during 2006.

Segment costs and expenses, which include operating, general and administrative costs, increased $2.94 billion year-to-year. Operating costs and expenses for this business segment increased $2.45 billion year-to-year as a result of higher cost of sales associated with Enterprise Products Partners’ natural gas, NGL and petrochemical marketing activities. Segment operating costs and expenses increased $188.1 million year-to-year attributable to acquired businesses and constructed assets Enterprise Products Partners placed in service since January 1, 2006. Operating costs and expenses associated with Enterprise Products Partners’ natural gas processing plants increased $185.7 million year-to-year as a result of higher energy commodity prices in 2007 relative to 2006. Segment general and administrative costs increased $22.5 million year-to-year primarily due to the recognition of a severance obligation in 2007 and an increase in legal fees.

Total segment operating income increased $15.7 million year-to-year due to strength in the underlying performance of Enterprise Products Partners’ business lines.

Segment operating income attributable to NGL Pipelines & Services increased $19.3 million year-to-year. 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 Enterprise Products Partners’ pipelines and fractionation facilities. This business line benefited from higher tariff rates on Enterprise Products Partners’ Mid-America Pipeline System and contributions to operating income during 2007 from its DEP South Texas NGL Pipeline. In addition, operating income for 2007 includes $32.7 million of proceeds from business interruption insurance claims compared to $40.4 million of proceeds during 2006.

Segment operating income attributable to Onshore Natural Gas Pipelines & Services decreased $40.0 million year-to-year primarily due to higher operating costs and expenses from Enterprise Products

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Partners’ Acadian System, Carlsbad Gathering System and Texas Intrastate System. Segment operating income attributable to Offshore Pipelines & Services increased $43.5 million year-to-year. Enterprise Products Partners’ Independence Hub platform and Independence Trail pipeline contributed $64.6 million to operating income during 2007. In addition, operating income for 2007 includes $3.4 million of proceeds from business interruption insurance claims compared to $23.5 million during 2006.

Segment operating income attributable to Petrochemical Services decreased $8.9 million year-to-year. Improved results from this business line attributable to higher butane isomerization processing volumes were more than offset by lower octane enhancement sales margins during 2007 relative to 2006.

Investment in TEPPCO. Segment revenues increased $171.4 million year-to-year primarily due to a gain related to the sale of equity interests in March 2007, higher crude oil prices and petroleum products sales volumes and higher pipeline throughput volumes during 2007 relative to 2006. TEPPCO recorded a gain of approximately $60.0 million related to the sale of equity interests in March 2007. TEPPCO’s marketing activities, primarily crude oil sales, accounted for $93.4 million of the increase in segment revenue. The remaining increase was primarily due to earnings growth from expansions on the Jonah system.

Segment costs and expenses increased $95.5 million year-to-year. Operating costs and expenses for this business segment increased $73.4 million year-to-year as a result of an increase in the cost of sales associated with TEPPCO’s marketing activities. The cost of sales of its petroleum products increased year-to-year due to higher sales volumes and energy commodity prices. The remainder of the year-to-year increase in segment costs and expenses is primarily attributable to higher pipeline operating and maintenance fees. Segment general and administrative costs increased $7.0 million year-to-year primarily due to expenses associated with office facilities and insurance costs.

Changes in TEPPCO’s revenues and costs and expenses year-to-year are explained in part by changes in energy commodity prices. The NYMEX market price of crude oil averaged $72.24 per barrel during 2007 compared to an average of $66.23 per barrel during 2006 – a 9% increase. The year-to-year increase in TEPPCO’s revenues and costs and expenses is partially offset by the effects of implementing new accounting guidance. Beginning in April 2006, TEPPCO ceased to record gross revenues and costs and expenses for sales of crude oil inventory under buy/sell agreements with the same counterparty. These transactions are currently presented on a net basis in our Statements of Consolidated Operations.

Segment operating income increased $62.2 million year-to-year primarily due to the underlying results of TEPPCO’s business lines. Prior to its February 2008 acquisition of the Marine Services business line, TEPPCO operated in three primary business lines: Downstream, Upstream and Midstream. Segment operating income attributable to Downstream increased $39.4 million year-to-year primarily due to improved results from TEPPCO’s pipeline operations and a gain that TEPPCO recorded in connection with its sale of equity interests and assets to a third-party in March 2007. Segment operating income attributable to Downstream benefited from a year-to-year increase in refined products transportation volumes.

Segment operating income attributable to Upstream increased $4.1 million year-to-year primarily due to higher crude oil sales volumes and prices during 2007 compared to 2006. Segment operating income attributable to Midstream increased $20.1 million year-to-year primarily due to earnings growth from expansions on the Jonah system. Natural gas gathering volumes on the Jonah system averaged 1.6 Bcf/d during 2007 compared to 1.3 Bcf/d during 2006.

Investment in Energy Transfer Equity. Segment operating income was $3.1 million for 2007. We recorded total equity earnings of $3.1 million from Energy Transfer Equity and LE GP for the period since our acquisition of such interests on May 7, 2007 through December 31, 2007. Our equity earnings from Energy Transfer Equity and LE GP were reduced by $26.7 million of excess cost amortization.

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Review of Consolidated Interest Expense Amounts

The following table presents the components of interest expense as presented in our Statements of Consolidated Operations for the periods indicated (dollars in thousands):

	For the Year Ended December 31,
	2008		2007		2006
Interest expense attributable to:
Consolidated debt obligations of Enterprise Products Partners	$	400,686	$	311,764	$	238,023
Consolidated debt obligations of TEPPCO		140,042		101,223		86,171
Parent Company debt obligations		67,495		74,432		9,548
Total interest expense	$	608,223	$	487,419	$	333,742

Interest expense for Enterprise Products Partners and TEPPCO increased in the current year periods relative to the prior year periods primarily due to borrowings made in connection with their respective capital spending programs. In addition, TEPPCO’s interest expense for year ended December 31, 2008 includes $8.7 million for losses it recognized on the early extinguishment of debt during the first quarter of 2008. See Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding our consolidated debt obligations, which include the consolidated debt obligations of Enterprise Products Partners and TEPPCO.

The Parent Company’s interest expense increased during the 2007 period as a result of borrowings it made during May 2007 to acquire interests in Energy Transfer Equity and LE GP.

Review of Consolidated Other Income, Net Amounts

On March 1, 2007, TEPPCO sold its 49.5% ownership interest in Mont Belvieu Storage Partners, L.P. (“MB Storage”) and its 50% ownership interest in Mont Belvieu Venture, LLC (the general partner of MB Storage) to Louis Dreyfus Energy Services L.P. for approximately $156.0 million in cash. TEPPCO recognized a gain of approximately $60.0 million related to its sale of these equity interests, which is included in our other income.

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Review of Consolidated Minority Interest Expense Amounts

Minority interest expense amounts attributable to the limited partners of Enterprise Products Partners, Duncan Energy Partners and TEPPCO primarily represent allocations of earnings by these entities to their unitholders, excluding those earnings allocated to the Parent Company in connection with its ownership of common units of Enterprise Products Partners and TEPPCO. The following table presents the components of minority interest expense as presented on our Statements of Consolidated Operations for the periods indicated (dollars in thousands):

	For Year Ended December 31,
	2008		2007		2006
Limited partners of Enterprise Products Partners (1)	$	786,528	$	404,779	$	486,398
Limited partners of Duncan Energy Partners (2)		17,300		13,879		--
Related party former owners of TEPPCO GP		--		--		16,502
Limited partners of TEPPCO (3)		153,592		217,938		126,606
Joint venture partners (4)		24,038		16,764		9,079
Total	$	981,458	$	653,360	$	638,585

(1) Minority interest expense attributable to this subsidiary increased in 2008 relative to 2007 primarily due to an increase in Enterprise Products Partners’ operating income, partially offset by an increase in interest expense. In addition, the number of Enterprise Products Partners’ common units outstanding increased in 2008 relative to 2007. (2) Duncan Energy Partners completed its initial public offering in February 2007. The increase in minority interest expense during 2008 is primarily due to an increase in Duncan Energy Partners’ net income. (3) Minority interest expense attributable to this subsidiary decreased in 2008 relative to 2007 primarily due to a decrease in TEPPCO’s net income in 2008. TEPPCO recognized an approximate $60.0 million gain on the sale of an equity investment in the first quarter of 2007. (4) Represents third-party ownership interests in joint ventures that we consolidate.

Liquidity and Capital Resources

On a consolidated basis, our primary cash requirements, in addition to normal operating expenses and debt service, are for capital expenditures, business combinations and distributions to partners and minority interest holders. Enterprise Products Partners and TEPPCO expect to fund their short-term needs for amounts such 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 cash flows from operating activities, borrowings under credit facilities, the issuance of additional equity and debt securities and proceeds from divestitures of ownership interests 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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The following table summarizes key components of our consolidated statements of cash flows for the periods indicated (dollars in thousands):

	For the Year Ended December 31,
	2008			2007			2006

Net cash flows provided by operating activities:
EPGP and Subsidiaries (1)	$	1,234,302		$	1,588,959		$	1,174,837
TEPPCO GP and Subsidiaries (2)		346,270			350,499			273,122
Parent Company (3)		234,772			184,673			166,123
Eliminations and adjustments (4)		(248,800	)		(187,297	)		(174,508	)
Net cash flows provided by operating activities	$	1,566,544		$	1,936,834		$	1,439,574
Cash used in investing activities:
EPGP and Subsidiaries (1)	$	(2,411,409	)	$	(2,553,607	)	$	(1,689,200	)
TEPPCO GP and Subsidiaries (2)		(831,020	)		(317,400	)		(273,716	)
Parent Company (3)		(7,735	)		(1,650,827	)		(18,920	)
Eliminations and adjustments		3,264			(19,264	)		11,189
Cash used in investing activities	$	(3,246,900	)	$	(4,541,098	)	$	(1,970,647	)
Cash provided by (used in) financing activities:
EPGP and Subsidiaries (1)	$	1,172,907		$	981,815		$	495,074
TEPPCO GP and Subsidiaries (2)		484,722			(33,154	)		594
Parent Company		(226,177	)		1,467,027			(146,928	)
Eliminations and adjustments (4)		264,327			206,792			163,086
Cash provided by financing activities	$	1,695,779		$	2,622,480		$	511,826

Cash on hand at end of period (unrestricted)	$	56,828		$	41,920		$	23,290

(1) Represents consolidated cash flow information reported by EPGP and subsidiaries, which includes Enterprise Products Partners. (2) Represents consolidated cash flow information reported by TEPPCO GP and subsidiaries, which includes TEPPCO. (3) Equity earnings and distributions from the Parent Company's Investment in Energy Transfer Equity are reflected as operating cash flows and its initial investment is reflected in investing activities. (4) Distributions received by the Parent Company from its Investments in Enterprise Products Partners and TEPPCO (as reflected in operating cash flows for the Parent Company) are eliminated against cash distributions paid to owners by EPGP, TEPPCO GP and their respective subsidiaries (as reflected in financing activities).

Net cash flows provided by operating activities are largely dependent on earnings from our consolidated businesses. 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, LPGs, crude oil and certain petrochemical products. 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 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, “Risk Factors,” of this annual report.

We use the indirect method to compute net cash flows provided by operating activities. See Note 22 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding this method of presentation.

Cash used in investing activities primarily represents expenditures for additions to property, plant and equipment, business combinations and investments in unconsolidated affiliates. Cash provided by (or used in) financing activities generally consists of borrowings and repayments of debt, distributions to partners, proceeds from the issuance of equity securities, and distributions and contributions to minority interests.

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Our consolidated debt obligations totaled $12.71 billion and $9.86 billion at December 31, 2008 and 2007, respectively. For detailed information regarding our consolidated debt obligations, see Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

For information regarding our risks in connection with the global financial crisis, see “The global financial crisis may have impacts on our business and financial position that we currently cannot predict,” under Item 1A, “Risk Factors,” of this annual report.

At December 31, 2008, Enterprise Products Partners and TEPPCO each have a universal shelf registration statement on file with the SEC that allows them to issue an unlimited amount of debt and equity securities. In March 2008, Duncan Energy Partners filed a universal shelf registration statement with the SEC that authorized its issuance of up to $1.00 billion in debt and equity securities. As of February 2, 2008, Duncan Energy Partners has issued $0.5 million in equity securities under this registration statement.

In addition, Enterprise Products Partners and TEPPCO each have registration statements on file with the SEC in connection with their respective distribution reinvestment programs (“DRIP”). The DRIP programs provide unitholders of record and beneficial owners of common units of Enterprise Products Partners and TEPPCO a voluntary means by which such unitholders and owners can increase the number of common units they own of each registrant by reinvesting the quarterly cash distributions they would otherwise receive into the purchase of additional common units of either Enterprise Products Partners or TEPPCO. In November 2008, affiliates of EPCO reinvested $3.3 million of the distributions they received from TEPPCO into the acquisition of additional common units of TEPPCO through its DRIP. In addition, in November 2008, the Parent Company and affiliates of EPCO reinvested $5.0 million and $62.0 million, respectively, of the distributions they each received from Enterprise Products Partners into the acquisition of additional common units of Enterprise Products Partners through its DRIP.

We forecast that Enterprise Products Partners’ capital spending for property, plant and equipment for 2009 will approximate $1.0 billion. In addition, we forecast that TEPPCO’s capital spending for 2009 will be approximately $340.0 million. These forecasts are based on Enterprise Products Partners’ and TEPPCO’s announced strategic operating and growth plans. These plans are dependent upon each entity’s ability to obtain the required funds from its operating cash flows or other means, including borrowings under debt agreements, the issuance of debt and equity securities and/or the divestiture of assets. Such forecasts may change due to factors beyond Enterprise Prodcuts Partners or TEPPCO's control, such as weather-related issues, changes in supplier prices or adverse economic conditions. Furthermore, such forecasts may change as a result of decisions made by management at a later date, which may include unexpected acquisitions, decisions to take on additional partners and changes in the timing of expenditures. The success of Enterprise Products Partners or TEPPCO in raising capital, including the formation of joint ventures to share costs and risks, continues to be a principal factor that determines how much each entity can spend in connection with their respective capital programs.

EPO’s publicly traded debt securities were rated investment-grade as of March 2, 2009. Moody’s Investor Service (“Moody’s”) assigned a rating of Baa3 and Standard & Poor’s and Fitch Ratings each assigned a rating of BBB-. The publicly traded debt securities of TEPPCO were also rated as investment-grade as of March 2, 2009. These debt securities are rated BBB- by Standard & Poor’s and Fitch Ratings and Baa3 by Moody’s.

As of March 2, 2009, the Parent Company’s credit facilities are rated Ba2, BB and BB- by Moody’s, Fitch Ratings and Standard & Poor’s, respectively. Recently, there has been limited access to the institutional leveraged loan market for companies with similar ratings to those of the Parent Company. At this time, we are unable to estimate when these market conditions will improve.

Cash Flow Analysis - EPGP and Subsidiaries

At December 31, 2008, total liquidity of EPGP and its consolidated subsidiaries (primarily Enterprise Products Partners) was $1.51 billion, which includes availability under Enterprise Products Partners’ consolidated credit facilities and unrestricted cash on hand. The principal amount of Enterprise Products Partners’ consolidated debt obligations totaled $9.05 billion at December 31, 2008. The following information highlights significant changes in the operating, investing and financing cash flows for EPGP and its consolidated subsidiaries.

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Comparison of 2008 with 2007

Operating Activities. Net cash flow provided by operating activities was $1.23 billion for 2008 compared to $1.59 billion for 2007. Although Enterprise Products Partners’ businesses generated higher earnings year-to-year, the reduction in operating cash flows is generally due to the timing of related cash receipts and disbursements. The overall $354.7 million year-to-year decrease in operating cash flows also reflects a $127.3 million decrease in cash proceeds Enterprise Products Partners received from insurance claims related to certain named storms. For information regarding proceeds from business interruption and property damage claims, see Note 21 of the Notes to Consolidated Statements included under Item 8 of this annual report. Enterprise Products Partners’ cash payments for interest increased $116.3 million year-to-year primarily due to increased borrowings to finance its capital spending program.

Investing Activities. Cash used in investing activities was $2.41 billion for 2008 compared to $2.55 billion for 2007. Capital spending for property, plant and equipment, net of contributions in aid of construction costs, decreased $174.6 million year-to-year. Cash outlays for investments in and advances to unconsolidated affiliates decreased $208.9 million year-to-year. Enterprise Products Partners contributed $216.5 million to Cameron Highway during the second quarter of 2007. Cameron Highway used these funds, along with an equal contribution from its other owner, to repay approximately $430.0 million of its outstanding debt.

Restricted cash related to Enterprise Products Partners' hedging activities increased $85.4 million year-to-year (a cash outflow). See Item 7A of this annual report for information regarding Enterprise Products Partners’ interest rate and commodity risk hedging portfolios.

Cash used for business combinations increased $166.4 million year-to-year primarily due to Enterprise Products Partners’ acquisition of a 100.0% membership interest in Great Divide Gathering, LLC for $125.2 million, the acquisition of remaining interests in Dixie for $57.1 million and the acquisition of additional interests in Tri-States NGL Pipeline, L.L.C. for $18.7 million.

Financing Activities. Cash provided by financing activities was $1.17 billion for 2008 compared to $981.8 million for 2007. Net borrowings under Enterprise Products Partners’ consolidated debt agreements increased $588.9 million year-to-year. Borrowings under debt agreements for 2008 include (i) the issuance of $400.0 million in principal amount of 5-year senior notes (“EPO Senior Notes M”) and $700.0 million in principal amount of 10-year senior notes (“EPO Senior Notes N”) in April 2008, (ii) the execution of a Japanese yen term loan agreement in the amount of 20.7 billion yen (approximately $217.6 million U.S. dollar equivalent) in November 2008 and (iii) the issuance of $500.0 million in principal amount of 5-year senior notes (“EPO Senior Notes O”) in December 2008. Enterprise Products Partners used the proceeds from these borrowings primarily to repay amounts borrowed under the EPO Revolver and, to a lesser extent, for general partnership purposes. For information regarding Enterprise Products Partners’ consolidated debt obligations, see Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Cash distributions paid by Enterprise Products Partners to its limited partners increased $62.4 million year-to-year due to increases in common units outstanding and quarterly cash distribution rates. Contributions from minority interests decreased $230.9 million year-to-year primarily due to the initial public offering of Duncan Energy Partners in February 2007.

The early termination and settlement by Enterprise Products Partners of interest rate hedging financial instruments during 2008 resulted in net cash payments of $14.4 million compared to net cash receipts of $48.9 million during 2007, which resulted in a $63.3 million decrease in financing cash flows between years.

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Comparison of 2007 with 2006

Operating Activities. Net cash flow provided by operating activities was $1.59 billion for 2007 compared to $1.17 billion for 2006. The $414.1 million year-to-year increase in net cash flows provided by operating activities was primarily due to increased earnings from Enterprise Products Partners’ businesses and the timing of related cash collections and disbursements between periods. The year-to-year increase in operating cash flows includes a $42.1 million increase in cash proceeds Enterprise Products Partners received from insurance claims related to certain named storms.

Investing Activities. Cash used in investing activities was $2.55 billion for 2007 compared to $1.69 billion for 2006. The $864.4 million overall increase in net cash outflows is primarily due to an $847.7 million increase in capital spending for property, plant and equipment (net of contributions in aid of construction costs) 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. Enterprise Products Partners contributed $216.5 million to Cameron Highway during the second quarter of 2007. As noted previously, Cameron Highway used these funds, along with an equal contribution from its other owner, to repay approximately $430.0 million of its outstanding debt. During 2006, Enterprise Products Partners paid $100.0 million for Piceance Creek Pipeline, LLC and $145.2 million in connection with its Encinal acquisition. Enterprise Products Partners’ spending for business combinations during 2007 was limited and primarily attributable to the $35.0 million it paid to acquire the South Monco pipeline business.

Financing Activities. Cash provided by financing activities was $981.8 million for 2007 versus $495.1 million for 2006. Net borrowings under Enterprise Products Partners’ consolidated debt agreements increased $1.10 billion year-to-year. In May 2007, EPO sold $700.0 million in principal amount of junior subordinated notes (“Junior Notes B”). In September 2007, EPO sold $800.0 million in principal amount of senior notes (“Senior Notes L”) and, in October 2007, EPO repaid $500.0 million in principal amount of senior notes (“Senior Notes E”).

Net proceeds from the issuance of Enterprise Products Partners’ common units decreased $788.0 million year-to-year. Underwritten equity offerings in March and September of 2006 generated net proceeds of $750.8 million reflecting the sale of 31.1 million common units of Enterprise Products Partners.

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 approximately $291.0 million from the sale of approximately 15.0 million of its common units.

Cash distributions to Enterprise Products Partners’ limited partners increased $90.6 million year-to-year due to an increase in common units outstanding and quarterly cash distribution rates. Enterprise Products Partners received $48.9 million from the settlement of treasury lock financial instruments during 2007 related to its interest rate risk hedging activities.

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Cash Flow Analysis - TEPPCO GP and Subsidiaries

At December 31, 2008, total liquidity of TEPPCO GP and its consolidated subsidiaries (primarily TEPPCO) was $404.4 million, which includes availability under TEPPCO’s consolidated credit facilities. The principal amount of TEPPCO’s consolidated debt obligations totaled $2.53 billion at December 31, 2008. The following information highlights significant changes in the operating, investing and financing cash flows for TEPPCO GP and its consolidated subsidiaries.

Comparison of 2008 with 2007

Operating Activities. Net cash flow provided by operating activities was $346.3 million for 2008 compared to $350.5 million for 2007. The $4.2 million decrease in operating cash flows is primarily due to the timing of cash receipts and disbursements between periods, partially offset by a $23.2 million increase in distributions from unconsolidated affiliates (primarily Jonah). TEPPCO’s cash payments for interest increased $23.9 million year-to-year primarily due to increased borrowings to finance its capital spending program.

Investing Activities. Cash used in investing activities was $831.0 million for 2008 compared to $317.4 million for 2007. The $513.6 million year-to-year increase in cash used for investing activities is primarily due to a $351.3 million increase in cash outlays for business combinations and a $165.1 million decrease in proceeds from the sale of assets. TEPPCO spent approximately $345.8 million in cash during 2008 to complete business combinations related to its new Marine Services business line. During 2007, TEPPCO reported $155.8 million of proceeds from the sale of certain equity interests and related storage assets located in Mont Belvieu, Texas.

Financing Activities. Cash provided by financing activities was $484.7 million for 2008 compared to cash used in financing activities of $33.2 million for 2007. Net borrowings under TEPPCO’s consolidated debt agreements increased $334.9 million year-to-year. In March 2008, TEPPCO sold $250.0 million in principal amount of 5-year senior notes, $350.0 million of 10-year senior notes and $400.0 million of 30-year senior notes. In January 2008, TEPPCO repaid $355.0 million in principal amount of the TE Products senior notes. In May 2007, TEPPCO sold $300.0 million in principal amount of its junior subordinated notes.

Net proceeds from the issuance of TEPPCO’s common units increased $274.2 million year-to-year. In September 2008, TEPPCO sold 9.2 million of its common units in an underwritten equity offering which generated net proceeds of $257.0 million. Cash distributions to TEPPCO’s limited partners increased $26.9 million year-to-year due to an increase in common units outstanding and quarterly cash distribution rates.

The early termination and settlement by TEPPCO of interest rate hedging financial instruments during 2008 resulted in net cash payments of $52.1 million compared to net cash receipts of $1.4 million during 2007, which resulted in a $53.5 million decrease in financing cash flows between years.

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Comparison of 2007 with 2006

Operating Activities. Net cash flow provided by operating activities was $350.5 million for 2007 compared to $273.1 million for 2006. The $77.4 million increase in operating cash flows is generally due to increased earnings of TEPPCO and the timing of related cash collections and disbursements between years. Operating income for 2007 attributable to our Investment in TEPPCO segment increased $62.2 million over 2006’s results as discussed under “Results of Operations” within this Item 7. TEPPCO’s cash payments for interest increased $16.1 million year-to-year primarily due to increased borrowings to finance its capital spending program.

Investing Activities. Cash used in investing activities was $317.4 million for 2007 compared to $273.7 million for 2006. The $43.7 million year-to-year increase in cash used for investing activities is primarily due to a $83.6 million increase in capital expenditures for property, plant and equipment and a $70.3 million increase in investments in unconsolidated affiliates (primarily Jonah), partially offset by a $113.5 million decrease in proceeds from the sale of assets.

TEPPCO reported $165.1 million of proceeds from the sale of assets during 2007 compared to $51.6 million during 2006. During the first quarter of 2007, TEPPCO sold its ownership interest in certain storage assets located in Mont Belvieu, Texas (along with other related assets) to a third party for $155.8 million. During the first quarter of 2006, TEPPCO sold a natural gas processing facility to Enterprise Products Partners for $38.0 million. The receipt of cash from Enterprise Products Partners is a component of TEPPCO GP and subsidiaries’ cash flows; however, this intercompany amount is eliminated in the preparation of our consolidated cash flow information.

Financing Activities. Cash used for financing activities was $33.2 million for 2007 compared to cash provided by financing activities of $0.6 million for 2006. TEPPCO’s net borrowings equaled its net proceeds in 2007 compared to net borrowings of $84.1 million in 2006. The 2007 period includes TEPPCO’s issuance of its junior subordinated notes in the principal amount of $300.0 million and the redemption of $35.0 million of its senior notes. Distributions increased $15.9 million year-to-year due to an increase in distribution-bearing units outstanding coupled with higher distribution rates per unit. Net cash proceeds from the issuance of TEPPCO’s common units were $1.7 million in 2007 compared to $195.1 million in 2006. TEPPCO issued 0.1 million of its common units in 2007 compared with 5.8 million in 2006.

Cash Flow Analysis - Parent Company

The primary sources of cash flow for the Parent Company are its investments in limited and general partner interests of publicly-traded limited partnerships. The cash distributions the Parent Company receives from its investments in Enterprise Products Partners, TEPPCO, Energy Transfer Equity and their respective general partners are exposed to certain risks inherent in the underlying business of each entity. For information regarding such risks, see Part I, Item 1A of this annual report.

The Parent Company’s primary cash requirements are for general and administrative costs, debt service costs, investments and distributions to partners. The Parent Company expects to fund its short-term cash requirements for such amounts as general and administrative costs using operating cash flows. Debt service requirements are expected to be funded by operating cash flows and/or refinancing arrangements. The Parent Company expects to fund its cash distributions to partners primarily with operating cash flows.

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The following table summarizes key components of the Parent Company’s cash flow information for the periods indicated (dollars in thousands):

	For the Year Ended December 31,
	2008			2007		2006

Net cash provided by operating activities (1)	$	234,772		$	184,673	$	166,123
Cash used in investing activities (2)		7,735			1,650,827		18,920
Cash provided by (used in) financing activities (3)		(226,177	)		1,467,027		(146,928	)
Cash and cash equivalents, end of period		2,516			1,656		783

(1) Primarily represents distributions received from unconsolidated affiliates less cash payments for interest and general and administrative costs. See following table for detailed information regarding distributions from unconsolidated affiliates. (2) Primarily represents investments in unconsolidated affiliates. (3) Primarily represents net cash proceeds from borrowings and equity offerings offset by repayments of debt principal and distribution payments to unitholders and former owners of TEPPCO GP. The amount presented for 2007 includes $739.4 million in net proceeds from an equity offering in July 2007.

The following table presents cash distributions received from unconsolidated affiliates and cash distributions paid by the Parent Company for the periods indicated (dollars in thousands):

	For the Year Ended December 31,
	2008		2007		2006
Cash distributions from investees: (1)
Enterprise Products Partners and EPGP:
From common units of Enterprise Products Partners (2)	$	27,514	$	25,766	$	24,150
From 2% general partner interest in Enterprise Products Partners		18,219		16,944		15,096
From general partner IDRs in distributions of
Enterprise Products Partners		123,855		104,652		84,802
TEPPCO and TEPPCO GP:
From 4,400,000 common units of TEPPCO		12,496		12,056		10,869
From 2% general partner interest in TEPPCO		5,573		5,023		4,014
From general partner IDRs in distributions of TEPPCO		49,353		43,210		43,077
Energy Transfer Equity and LE GP: (3)
From 38,976,090 common units of Energy Transfer Equity		76,004		29,720		--
From 34.9% member interest in LE GP		492		224		--
Total cash distributions received	$	313,506	$	237,595	$	182,008

Distributions by the Parent Company:
EPCO and affiliates	$	158,947	$	125,875	$	93,910
Public		54,175		33,153		14,528
General partner interest		21		14		11
Total distributions by the Parent Company (4)	$	213,143	$	159,042	$	108,449

Distributions paid to affiliates of EPCO that were the former
owners of the TEPPCO and TEPPCO GP interests contributed
to the Parent Company in May 2007 (5)	$	--	$	29,760	$	57,960

(1) Represents cash distributions received during each reporting period. (2) Prior to November 2008, the Parent Company owned 13,454,498 common units of Enterprise Products Partners. In November 2008, the Parent Company used $5.0 million in distributions received from Enterprise Products Partners with respect to the third quarter of 2008 to purchase an additional 216,427 common units. As of December 31, 2008, the Parent Company owned 13,670,925 common units of Enterprise Products Partners. (3) The Parent Company received its first cash distribution from Energy Transfer Equity and LE GP in July 2007. (4) The quarterly cash distributions paid by the Parent Company increased effective with the August 2007 distribution due to the issuance of 20,134,220 Units in July 2007. (5) Represents cash distributions paid to affiliates of EPCO that were former owners of these partnership and membership interests prior to the contribution of such interests to the Parent Company in May 2007.

For additional financial information pertaining to the Parent Company, see Note 24 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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The amount of cash distributions the Parent Company is able to pay its unitholders may fluctuate based on the level of distributions it receives from Enterprise Products Partners, TEPPCO, Energy Transfer Equity and their respective general partners. For example, if EPO is not able to satisfy certain financial covenants in accordance with its credit agreements, Enterprise Products Partners would be restricted from making quarterly cash distributions to its partners. Factors such as capital contributions, debt service requirements, general, administrative and other expenses, reserves for future distributions and other cash reserves established by the board of directors of EPE Holdings may affect the distributions the Parent Company makes to its unitholders. The Parent Company’s credit agreements contain covenants requiring it to maintain certain financial ratios. Also, the Parent Company is prohibited from making any distribution to its unitholders if such distribution would cause an event of default or otherwise violate a covenant under its credit agreements.

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 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. Examples of such circumstances include: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values; or (iv) changes in the forecast life of applicable resource basins, if any.

At December 31, 2008 and 2007, the net book value of our property, plant and equipment was $16.72 billion and $14.30 billion, respectively. We recorded $595.5 million, $515.4 million, and $434.6 million in depreciation expense for the years ended December 31, 2008, 2007 and 2006, respectively.

For additional information regarding our property, plant and equipment, see Notes 2 and 11 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Measuring recoverability of long-lived assets with finite lives

Long-lived assets include property, plant and equipment and intangible assets with finite useful lives. These assets are reviewed for impairment whenever events or changes in circumstances indicate that their carrying values may not be recoverable. Examples of such circumstances include (i) an unexpected and material decline in natural gas and crude oil production resulting in a decrease in throughput and processing volumes for our assets and (ii) a long-term decrease in the demand for natural gas, crude oil or NGLs that results in an economic downturn in the midstream energy industry.

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. A long-lived asset’s carrying value is deemed not recoverable if it exceeds the sum of the asset’s estimated undiscounted future cash flows, including those associated with the eventual disposition of the asset. Our estimates of undiscounted future cash flows are based on a number of assumptions including: (i) the asset’s anticipated future operating margins and volumes; (ii) the asset’s estimated useful (or economic) life; and (iii) the asset’s estimated salvage value, if

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applicable. If warranted, we record an impairment charge for the excess of a long-lived asset’s carrying value over its estimated fair value, which reflects an asset’s market value, replacement cost estimates and future earnings potential.

For the year ended December 31, 2006, we recorded $0.1 million of non-cash asset impairment charges related to property, plant and equipment, which are reflected as components of operating costs and expenses. No such asset impairment charges were recorded in 2008 or 2007.

For additional information regarding our property, plant and equipment and intangible assets, see Notes 11 and 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Measuring recoverability of goodwill

Goodwill represents the excess of the purchase price paid to complete a business combination over the respective fair value of assets acquired and liabilities assumed in the transaction.

We do not amortize goodwill; however, we test goodwill amounts for impairment annually, or more frequently if circumstances indicate that it is more likely than not that the fair value of goodwill is less than its carrying value. Goodwill amounts attributable to our Investment in Enterprise Products Partners segment are tested during the second quarter of each fiscal year. Goodwill amounts attributable to our Investment in TEPPCO segment are tested during the fourth quarter of each fiscal year.

Goodwill testing involves the determination of a reporting unit’s estimated fair value, which considers the reporting unit’s market value and future earnings potential. Our estimate of a reporting unit’s fair value is based on a number of assumptions including: (i) the discount rate we select to present value underlying cash flow streams; (ii) the reporting unit’s future operating margins and volumes for a discrete forecast period; and (iii) the reporting units long-term growth rate beyond the discrete forecast period. If the estimated 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. The financial models we develop to estimate a reporting unit’s fair value are sensitive to changes in these assumptions. Consequently, a significant change in any of these underlying assumptions may result in our recording an impairment charge where none was warranted in prior periods.

At December 31, 2008 and 2007, the carrying value of our goodwill was $1.01 billion and $807.6 million, respectively. We did not record any goodwill impairment charges during the years ended December 31, 2008, 2007 and 2006.

For additional information regarding our goodwill, see Note 14 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Measuring recoverability of intangible assets with indefinite lives

At December 31, 2008 and 2007, the Parent Company had an indefinite-life intangible asset valued at $606.9 million associated with IDRs in TEPPCO’s quarterly cash distributions. This intangible asset is not subject to amortization, but is subject to periodic testing for recoverability in a manner similar to goodwill. In addition, we review this asset annually to determine whether events or circumstances continue to support an indefinite life. The IDRs represent contractual rights to the incentive cash distributions paid by TEPPCO. Such rights were granted to TEPPCO GP under the terms of TEPPCO’s partnership agreement. In accordance with TEPPCO’s partnership agreement, TEPPCO GP may separate and sell the IDRs independent of its other residual general partner and limited partner interests in TEPPCO.

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renewal provisions that provide for TEPPCO to continue as a going concern beyond the initial term of its partnership agreement, which ends in December 2084.

We test the carrying value of the IDRs for impairment annually, or more frequently if circumstances indicate that it is more likely than not that the fair value of the asset is less than its carrying value. This test is performed during the fourth quarter of each fiscal year. If the estimated fair value of this intangible asset is less than its carrying value, a charge to earnings is required to reduce the asset’s carrying value to its implied fair value.

Our estimate of the fair value of this asset is based on a number of assumptions including: (i) the discount rate we select to present value underlying cash flow streams; (ii) the expected increase in TEPPCO’s cash distribution rate over a discreet forecast period; and (iii) the long-term growth rate of TEPPCO’s cash distributions beyond the discreet forecast period. The financial models we use to estimate the fair value of the IDRs are sensitive to changes in these assumptions. Consequently, a significant change in any of these underlying assumptions may result in our recording an impairment charge where none was warranted in prior periods.

We did not record any impairment charges in connection with our indefinite-lived intangible assets during the years ended December 31, 2008, 2007 and 2006.

For additional information regarding the TEPPCO IDRs, see Note 24 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Measuring recoverability of equity method investments

We evaluate equity method investments for impairment whenever events or changes in circumstances indicate an other than temporary decline in the value of the investment. Examples of such circumstances include a history of operating losses by the entity and/or a long-term adverse change in the entity’s industry.

The carrying value of an equity method investment is deemed not recoverable if it exceeds the sum of estimated discounted future cash flows we expect to derive from the investment. Our estimates of discounted future cash flows are based on a number of assumptions including: (i) the discount rate we select to present value underlying cash flow streams; (ii) the probabilities we assign to different future cash flow scenarios; (iii) the entity’s anticipated future operating margins and volumes; and (iv) the estimated economic life of the entity’s underlying assets. The financial models we develop to test such investments for impairment are sensitive to changes in these assumptions. Consequently, a significant change in any of these underlying assumptions may result in our recording an impairment charge where none was warranted in prior periods.

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, 2008.

For additional information regarding impairment charges associated with our equity method investments, see Note 12 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Amortization methods and estimated useful lives of finite-lived intangible assets

We have recorded intangible assets in connection with certain contracts, customer relationships and similar finite-lived agreements acquired in connection with business combinations and asset purchases.

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Contract-based intangible assets represent specific commercial rights we acquired in connection with business combinations or asset purchases. Examples of such agreements include the Jonah and Val Verde natural gas gathering agreements, Shell processing agreement and Mississippi natural gas storage contracts. Contract-based intangible assets are amortized over their estimated useful life using methods that closely resemble the pattern in which the economic benefits of the contract are expected to be realized by us. For example, the Jonah and Val Verde natural gas gathering agreements are being amortized to earnings using a units-of-production method that closely resembles the pattern in which the economic benefits of the underlying natural gas resource bases are expected to be consumed or otherwise used, which correlates with amounts we expect to realize from gathering services rendered under these contracts. Other contracts such as the Shell processing agreement and Mississippi natural gas storage contracts are being amortized to earnings over their respective contract terms using a straight-line method, which closely matches the benefits we expect to realize from services rendered under these contracts. Our estimates of the useful life of contract-based intangible assets are predicated on a number of factors, including (i) contractual provisions that enable us to renew or extend such agreements, (ii) any legal or regulatory developments that would impact such contractual rights, (iii) volumetric estimates with respect to contracts amortized on a units-of-production basis, and (iv) the expected useful life of related fixed assets.

Customer relationship intangible assets represent the estimated economic value assigned to certain relationships acquired in connection with business combinations and asset purchases whereby (i) we acquired information about or access to customers and now have regular contact with them and (ii) the customers now have the ability to make direct contact with us. Customer relationships may arise from contractual arrangements (such as supplier contracts and service contracts) and through means other than contracts, such as through regular contact by sales or service representatives. The values assigned to our customer relationship intangible assets are being amortized to earnings using a method that closely resembles the pattern in which the economic benefits of the underlying crude oil and natural gas resource bases are expected to be consumed or otherwise used, which correlates with amounts we expect to realize from such relationships. 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.

If our underlying assumptions regarding the estimated useful life of an intangible asset changes, 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.

For additional information regarding our intangible assets, see Note 14 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: (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) collectibility is reasonably assured. When revenue transactions are settled, we record any necessary allowance for doubtful accounts.

Our use of estimates in recording 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 time it takes to compile actual billing information and receive third-party data needed to record transactions for financial accounting and reporting purposes. Two examples of estimates are the accrual 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 reporting period. Such estimates reverse in the following month and are offset by the corresponding actual customer billing and vendor-invoiced amounts.

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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, after adjusting for 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. Management reviews its estimates based on currently available information. Changes in facts and circumstances may result in revised estimates.

For additional information regarding our revenue recognition policies, see Note 5 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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 sites where specified substances have been released or disposed of. We accrue reserves for estimated environmental remediation costs when (i) our assessments indicate that it is probable that a liability has been incurred and (ii) a dollar 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 required remediation activities. We follow the provisions of American Institute of Certified Public Accounts (“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. Future environmental developments, such as new environmental laws or additional claims for damages, could result in costs beyond our current level of reserves. 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. At December 31, 2008 and 2007, none of our estimated environmental remediation liabilities are discounted to present value since the ultimate amount and timing of cash payments for such liabilities are not readily determinable.

At December 31, 2008 and 2007, our reserves for environmental remediation costs were $22.3 million and $30.5 million, respectively. For additional information regarding our environmental costs, see Note 2 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Natural gas imbalances

In the pipeline transportation business, 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 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. 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, 2008 and 2007, our natural gas imbalance receivables, net of allowance for doubtful accounts, were $63.4 million and $73.9 million, respectively, and are reflected as a component of “Accounts and notes receivable – trade” on our Consolidated Balance Sheets included under Item 8 of this annual report. At December 31, 2008 and 2007, our imbalance payables were $50.8 million and $48.7 million, respectively, and are reflected as a component of “Accrued product payables” on our Consolidated Balance Sheets included under Item 8 of this annual report.

For additional information regarding our natural gas imbalances, see Note 2 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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Other Items

Contractual Obligations

The following table summarizes our significant contractual obligations as of December 31, 2008 (dollars in thousands).

			Payment or Settlement due by Period
			Less than		1-3		4-5		More than
Contractual Obligations	Total		1 year		years		years		5 years
Scheduled maturities of long-term debt: (1)
Parent Company	$	1,077,000	$	--	$	17,000	$	261,000	$	799,000
Enterprise Products Partners	$	9,046,046	$	--	$	1,488,250	$	2,267,596	$	5,290,200
TEPPCO	$	2,516,653	$	--	$	--	$	1,466,653	$	1,050,000
Estimated cash payments for interest: (2)
Parent Company	$	327,858	$	64,121	$	121,594	$	100,542	$	41,601
Enterprise Products Partners	$	9,351,928	$	544,658	$	993,886	$	821,123	$	6,992,261
TEPPCO	$	2,624,101	$	146,838	$	293,676	$	215,449	$	1,968,138
Operating lease obligations (3)	$	388,291	$	44,901	$	75,829	$	66,861	$	200,700
Purchase obligations: (4)
Product purchase commitments:
Estimated payment obligations:
Crude oil	$	161,194	$	161,194	$	--	$	--	$	--
Refined products	$	1,642	$	1,642	$	--	$	--	$	--
Natural gas	$	5,225,141	$	323,309	$	1,150,102	$	1,148,610	$	2,603,120
NGLs	$	1,923,792	$	969,870	$	272,672	$	272,500	$	408,750
Petrochemicals	$	1,746,138	$	685,643	$	624,393	$	268,418	$	167,684
Other	$	66,657	$	24,221	$	14,159	$	12,865	$	15,412
Underlying major volume commitments:
Crude oil (in MBbls)		3,404		3,404		--		--		--
Refined products (in MBbls)		28		28		--		--		--
Natural gas (in BBtus)		981,955		56,650		209,075		214,730		501,500
NGLs (in MBbls)		56,622		23,576		9,446		9,440		14,160
Petrochemicals (in MBbls)		67,696		24,949		23,848		11,665		7,234
Service payment commitments (5)	$	534,426	$	57,289	$	100,752	$	93,167	$	283,218
Capital expenditure commitments (6)	$	786,675	$	786,675	$	--	$	--	$	--
Other long-term liabilities, as reflected
in our Consolidated Balance Sheet (7)	$	123,811	$	2,230	$	37,116	$	15,286	$	69,179
Total	$	35,901,353	$	3,812,591	$	5,189,429	$	7,010,070	$	19,889,263

(1) Represents our scheduled future maturities of consolidated debt obligations. For additional information on our consolidated debt obligations, see Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report. (2) Our estimated cash payments for interest are based on the principal amount of consolidated debt obligations outstanding at December 31, 2008. With respect to variable-rate debt, we applied the weighted-average interest rates paid during 2008. See Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding variable interest rates charged in 2008 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, 2008. See Note 8 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding our interest rate swap agreements. Our estimated cash payments for interest are significantly influenced by the long-term maturities of EPO’s $550.0 million Junior Notes A (due August 2066) and $682.7 million Junior Notes B (due January 2068) and TEPPCO’s $300.0 million Junior Subordinated Notes (due June 2067). Our estimated cash payments for interest assume that the EPO and TEPPCO 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 price under terms of each agreement at December 31, 2008. (5) Represents future payment commitments for services provided by third-parties. (6) Represents short-term unconditional payment obligations relating to our capital projects and those of our unconsolidated affiliates to vendors for services rendered or products purchased. (7) Other long-term liabilities as reflected on our Consolidated Balance Sheet at December 31, 2008 primarily represent (i) asset retirement obligations expected to settled in periods beyond 2012, (ii) reserves for environmental remediation costs that are expected to settle beginning in 2009 and afterwards and (iii) guarantee agreements relating to Centennial.

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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 of Enterprise Products Partners and TEPPCO, 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 position, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources. The following information summarizes the significant terms of such unconsolidated debt obligations.

Poseidon. At December 31, 2008, Poseidon’s debt obligations consisted of $109.0 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, 2008, Evangeline’s debt obligations consisted of (i) $8.2 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. Duncan Energy Partners had $1.0 million of letters of credit outstanding on December 31, 2008 that were furnished on behalf of Evangeline’s debt.

Centennial. At December 31, 2008, Centennial’s debt obligations consisted of $129.9 million borrowed under a master shelf loan agreement. Borrowings under the master shelf agreement mature in May 2024 and are collateralized by substantially all of Centennial’s assets and severally guaranteed by Centennial’s owners. Specifically, TEPPCO and its joint venture partner in Centennial have each guaranteed one-half of Centennial’s debt obligations. If Centennial defaults on its debt obligations, the estimated payment obligation for TEPPCO is $65.0 million at December 31, 2008.

Summary of Related Party Transactions

We have an extensive and ongoing relationship with EPCO and its private company affiliates. Our revenues from these entities primarily consist of sales of NGL products. Our expenses attributable to these affiliates primarily consist of reimbursements under an administrative services agreement.

We acquired equity method investments in Energy Transfer Equity in May 2007. As a result, Energy Transfer Equity became a related party to us. The majority of our revenues from Energy Transfer Equity are primarily from NGL marketing activities.

Many of our unconsolidated affiliates perform supporting or complementary roles to our consolidated business operations. Our revenues from unconsolidated affiliates primarily relate to natural gas sales to Evangeline and NGL sales to Energy Transfer Equity. The majority of our expenses with unconsolidated affiliates pertain to payments Enterprise Products Partners makes to K/D/S Promix, L.L.C. for NGL transportation, storage and fractionation services.

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.

Recent Accounting Developments

The accounting standard setting bodies have recently issued the following accounting guidance that will affect our future financial statements:

§	Statement of Financial Accounting Standards (“SFAS”) 141(R), Business Combinations;

§	FASB Staff Position SFAS 142-3, Determination of the Useful Life of Intangible Assets;

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§	SFAS 157, Fair Value Measurements;

§	SFAS 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB No. 51;

§	SFAS 161, Disclosures about Derivative Instruments and Hedging Activities – An Amendment of SFAS 133; and

§	Emerging Issue Task Force (“EITF”) 08-6, Equity Method Investment Accounting Considerations.

For additional information regarding recent accounting developments, see Note 3 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

Significant Risks and Uncertainties

Weather-Related Risks. We participate as named insureds in EPCO’s insurance program, which provides us with property damage, business interruption and other coverages, the scope and amounts of which are customary and sufficient for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance will not cover every type of damage or interruption that might occur. 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, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient to reimburse us for our 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 our partners and, accordingly, adversely affect the market price of our common units.

For windstorm events such as hurricanes and tropical storms, EPCO’s deductible for onshore physical damage is $10.0 million per storm. For offshore assets, the windstorm deductible is $10.0 million per storm plus a one-time $15.0 million aggregate deductible per policy period. To qualify for business interruption coverage in connection with a windstorm event, covered assets must be out-of-service in excess of 60 days for onshore assets and 75 days for offshore assets. For non-windstorm events, EPCO’s deductible for onshore and offshore physical damage is $5.0 million per occurrence. To qualify for business interruption coverage in connection with a non-windstorm event, covered onshore and offshore assets must be out-of-service in excess of 60 days. In meeting the deductible amounts, property damage costs are aggregated for EPCO and its affiliates, including us. Accordingly, our exposure with respect to the deductibles may be equal to or less than the stated amounts depending on whether other EPCO or affiliate assets are also affected by an event.

In the third quarter of 2008, Enterprise Products Partners’ onshore and offshore facilities located along the Gulf Coast of Texas and Louisiana were adversely impacted by Hurricanes Gustav and Ike. To a lesser extent, these storms affected the operations of TEPPCO as well. The disruptions in natural gas, NGL and crude oil production caused by these storms resulted in decreased volumes for some of Enterprise Products Partners’ pipeline systems, natural gas processing plants, NGL fractionators and offshore platforms, which, in turn, caused a decrease in operating income from these operations. As a result of our allocated share of EPCO’s insurance deductibles for windstorm coverage, Enterprise Products Partners and TEPPCO expensed $47.9 million and $1.0 million, respectively, of repair costs for property damage in connection with these two storms. Enterprise Products Partners’ expects to file property damage insurance claims to the extent repair costs exceed deductible amounts. Due to the recent nature of these storms, Enterprise Products Partners and TEPPCO are still evaluating the total cost of repairs and the potential for business interruption claims on certain assets.

See Note 21 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding insurance matters in connection with Hurricanes Katrina and Rita.

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FERC and CFTC Investigation – Energy Transfer Equity. In July 2007, ETP announced that it was under investigation by the Commodity Futures Trading Commission (“CFTC”) with respect to whether ETP engaged in manipulation or improper trading activities in the Houston Ship Channel market around the time of the hurricanes in the fall of 2005 and other prior periods in order to benefit financially from commodity financial instrument positions and from certain index-priced physical gas purchases in the Houston Ship Channel market. In March 2008, ETP entered into a consent order with the CFTC. Pursuant to this consent order, ETP agreed to pay the CFTC $10.0 million and the CFTC agreed to release ETP and its affiliates, directors and employees from all claims or causes of action asserted by the CFTC in this proceeding. ETP neither admitted nor denied the allegations made by the CFTC in this proceeding. The settlement was paid in March 2008.

In July 2007, ETP announced that it was also under investigation by the Federal Energy Regulatory Commission (the “FERC”) for the same matters noted in the CFTC proceeding described above. The FERC is also investigating certain of ETP’s intrastate transportation activities. The FERC’s actions against ETP also included allegations related to its Oasis pipeline, which is an intrastate pipeline that transports natural gas between the Waha and Katy hubs in Texas. The Oasis pipeline transports interstate natural gas pursuant to NGPA Section 311 authority, and is subject to FERC-approved rates, terms and conditions of service. The allegations related to the Oasis pipeline included claims that the pipeline violated NGPA regulations from January 2004 through June 2006 by granting undue preference to ETP’s affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation.

In July 2007, the FERC announced that it was taking preliminary action against ETP and proposed civil penalties of $97.5 million and disgorgement of profits, plus interest, of $70.1 million. In October 2007, ETP filed a response with the FERC refuting the FERC’s claims as being fundamentally flawed and requested a dismissal of the FERC’s proceedings. In February 2008, the FERC staff recommended an increase in the proposed civil penalties of $25.0 million and disgorgement of profits of $7.3 million. The total amount of civil penalties and disgorgement of profits sought by the FERC is approximately $200.0 million. In March 2008, ETP responded to the FERC staff regarding the recommended increase in the proposed civil penalties. In April 2008, the FERC staff filed an answer to ETP’s March 2008 pleading. The FERC has not taken any actions related to the recommendations of its staff with respect to the proposed increase in civil penalties. In May 2008, the FERC ordered hearings to be conducted by FERC administrative law judges with respect to the FERC’s intrastate transportation claims and market manipulation claims. The hearing related to the intrastate transportation claims involving the Oasis pipeline was scheduled to commence in December 2008 with the administrative law judge’s initial decision due in May 2009; however, as discussed below, ETP entered into a settlement agreement with FERC Enforcement Staff and that agreement was approved by the FERC in its entirety and without modification on February 27, 2009. The hearing related to the market manipulation claims is scheduled to commence in June 2009 with the administrative law judge’s initial decision due in December 2009. The FERC denied ETP’s request for dismissal of the proceeding and has ordered that, following completion of the hearings, the administrative law judge make recommendations with respect to whether ETP engaged in market manipulation in violation of the Natural Gas Act and FERC regulations, and, whether ETP violated the Natural Gas Policy Act (“NGPA”) and FERC regulations related to ETP’s intrastate transportation activities. The FERC reserved for itself the issues of possible civil penalties, revocation of ETP’s blanket market certificate, method by which ETP would disgorge any unjust profits and whether any conditions should be placed on ETP’s NGPA Section 311 authorization. Following the issuance of each of the administrative law judges’ initial decisions, the FERC would then issue an order with respect to each of these matters. ETP management has stated that it expects that the FERC will require a payment in order to conclude these investigations on a negotiated settlement basis.

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In November 2008, the administrative law judge presiding over the Oasis claims granted ETP’s motion for summary disposition of the claim that Oasis unduly discriminated in favor of affiliates regarding the provision of Section 311(a)(2) interstate transportation service. Oasis subsequently entered into an agreement with the Enforcement Staff to settle all claims related to Oasis. In January 2009, this agreement was submitted under seal to the FERC by the presiding administrative law judge for the FERC’s approval as an uncontested settlement of all Oasis claims. On February 27, 2009, the settlement agreement was approved by the FERC in its entirety and without modification and the terms of the settlement were made public. If no person seeks rehearing of the order approving the settlement within thirty days of such order, the FERC’s order will become final and non-appealable. ETP has stated that it does not believe the Oasis settlement, as approved by the FERC, will have a material adverse effect on it business, financial position or results of operations.

In addition to the CFTC and FERC, third parties have asserted claims, and may assert additional claims, against Energy Transfer Equity and ETP for damages related to the aforementioned matters. Several natural gas producers and a natural gas marketing company have initiated legal proceedings against Energy Transfer Equity and ETP in Texas state courts for claims related to the FERC claims. These suits contain contract and tort claims relating to the alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index during the period from December 2003 through December 2006, and seek unspecified direct, indirect, consequential and exemplary damages. Energy Transfer Equity and ETP are seeking to compel arbitration in several of these suits on the grounds that the claims are subject to arbitration agreements, and one suit is pending before the Texas Supreme Court on issues of arbitrability. One of the suits against Energy Transfer Equity and ETP contains an additional allegation that the defendants transported natural gas in a manner that favored their affiliates and discriminated against the plaintiff, and otherwise artificially affected the market price of natural gas to other parties in the market. ETP has moved to compel arbitration and/or contested subject-matter jurisdiction in some of these cases. One such case currently is on appeal before the Texas Supreme Court on, among other things, the issue of whether the dispute is arbitrable.

ETP has also been served with a complaint from an owner of royalty interests in natural gas producing properties, individually and on behalf of a putative class of similarly situated royalty owners, working interest owners and producers/operators, seeking arbitration to recover damages based on alleged manipulation of natural gas prices at the Houston Ship Channel. ETP filed an original action in Harris County, Texas seeking a stay of the arbitration on the grounds that the action is not arbitrable, and the state court granted ETP their motion for summary judgment on that issue. The claimants have filed a motion of appeal.

A consolidated class action complaint has been filed against ETP and certain affiliates in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in intentional and unlawful manipulation of the price of natural gas futures and options contracts on the NYMEX in violation of the Commodity Exchange Act (“CEA”). It is further alleged that during the class period December 2003 to December 2005, ETP had the market power to manipulate index prices, and that ETP used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, in order to benefit its natural gas physical and financial trading positions and intentionally submitted price and volume trade information to trade publications. This complaint also alleges that ETP also violated the CEA because ETP knowingly aided and abetted violations of the CEA. This action alleges that the unlawful depression of index prices by ETP manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels during the period stipulated in the complaint, causing unspecified damages to the plaintiff and all other members of the putative class who purchased and/or sold natural gas futures and options contracts on the NYMEX during the period. This class action complaint consolidated two class actions which were pending against ETP. Following the consolidation order, the plaintiffs who had filed these two earlier class actions filed a consolidated complaint. They have requested certification of their suit as a class action, unspecified damages, court costs and other appropriate relief. In January 2008, ETP filed a motion to dismiss this suit on the grounds of failure to allege facts sufficient to state a claim. In March 2008, the plaintiffs filed a second consolidated class action complaint. In response to this new pleading, ETP filed a motion to dismiss this second consolidated complaint in May 2008. In June 2008, the plaintiffs filed a response opposing ETP’s motion to dismiss. ETP filed a reply in support of its motion in July 2008.

In March 2008, another class action complaint was filed against ETP in the United States District Court for the Southern District of Texas. This action alleges that ETP engaged in unlawful restraint of trade and intentional monopolization and attempted monopolization of the market for fixed-price natural gas baseload transactions at the Houston Ship Channel from December 2003 through December 2005 in violation of federal antitrust law. The complaint further alleges that during this period ETP exerted monopolistic power to suppress the price of these transactions to non-competitive levels in order to benefit from its own physical natural gas positions. The plaintiff has, individually and on behalf of all other similarly situated sellers of physical natural gas, requested certification of its suit as a class action and seeks

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unspecified treble damages, court costs and other appropriate relief. In May 2008, ETP filed a motion to dismiss this complaint. In July 2008, the plaintiffs filed a response opposing ETP’s motion to dismiss. ETP filed a reply in support of its motion in August 2008.

At this time, ETE is unable to predict the outcome of these matters; however, it is possible that the amount it becomes obliged to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of its existing accrual related to these matters.

ETP disclosed in its annual report on Form 10-K for the year ended December 31, 2008 that its accrued amounts for contingencies and current litigation matters (excluding environmental matters) aggregated $20.8 million at December 31, 2008. Since ETP’s accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from its operating cash flows or from borrowings. If these payments are substantial, ETP and, ultimately, our investee, Energy Transfer Equity, may experience a material adverse impact on their results of operations, cash available for distribution and liquidity.

See Note 20 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for additional information regarding our litigation-related matters.

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. We may use financial instruments (e.g., futures, forwards, swaps, options and other financial instruments with similar characteristics) to mitigate the risks of certain identifiable and anticipated transactions. In general, the types of risks we attempt to hedge are those related to (i) the variability of future earnings, (ii) fair values of certain debt obligations and (iii) cash flows resulting from changes in applicable interest rates, commodity prices or exchange rates.

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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The following table presents gains (losses) recorded in net income attributable to our interest rate risk and commodity risk hedging transactions for the periods indicated (dollars in thousands). These amounts do not present the corresponding gains (losses) attributable to the underlying hedged items.

	For the Year Ended December 31,
	2008			2007			2006
Interest Rate Risk Hedging Portfolio:
Parent Company:
Ineffective portion of cash flow hedges	$	866		$	(2,127	)	$	--
Reclassification of cash flow hedge amounts from AOCI, net		(6,610	)		742			--
Enterprise Products Partners (excluding Duncan Energy Partners):
Reclassification of cash flow hedge amounts from AOCI, net		4,409			5,429			4,234
Other gains (losses) from derivative transactions		5,340			(8,934	)		(5,195	)
Duncan Energy Partners:
Ineffective portion of cash flow hedges		(5	)		(155	)		--
Reclassification of cash flow hedge amounts from AOCI, net		(2,008	)		350			--
TEPPCO:
Ineffective portion of cash flow hedges		(43	)		--			--
Reclassification of cash flow hedge amounts from AOCI, net		(4,924	)		64			--
Loss from treasury lock cash flow hedge		(3,586	)		--			--
Other gains (losses) from derivative transactions		4,056			5,202			8,568
Total hedging gains (losses), net, in consolidated interest expense	$	(2,505	)	$	571		$	7,607

Commodity Risk Hedging Portfolio:
Enterprise Products Partners:
Reclassification of cash flow hedge amounts from AOCI, net - natural gas marketing activities	$	(30,175	)	$	(3,299	)	$	(1,327	)
Reclassification of cash flow hedge amounts from AOCI, net - NGL and petrochemical operations		(28,232	)		(4,564	)		13,891
Other gains (losses) from derivative transactions		29,772			(20,712	)		(2,307	)
TEPPCO:
Reclassification of cash flow hedge amounts from AOCI, net		(37,898	)		(1,654	)		261
Other gains (losses) from derivative transactions		(343	)		189			(96	)
Total hedging gains (losses), net, in consolidated operating costs and expenses	$	(68,876	)	$	(30,040	)	$	10,422

The following table provides additional information regarding derivative assets and derivative liabilities included in our Consolidated Balance Sheets at the dates indicated (dollars in thousands):

	At December 31,
	2008		2007
Current assets:
Derivative assets:
Interest rate risk hedging portfolio	$	7,780	$	637
Commodity risk hedging portfolio		201,473		10,796
Foreign currency risk hedging portfolio		9,284		1,308
Total derivative assets – current	$	218,537	$	12,741
Other assets:
Interest rate risk hedging portfolio	$	38,939	$	14,744
Total derivative assets – long-term	$	38,939	$	14,744

Current liabilities:
Derivative liabilities:
Interest rate risk hedging portfolio	$	19,205	$	49,689
Commodity risk hedging portfolio		296,850		48,930
Foreign currency risk hedging portfolio		109		27
Total derivative liabilities – current	$	316,164	$	98,646
Other liabilities:
Interest rate risk hedging portfolio	$	17,131	$	13,047
Commodity risk hedging portfolio		233		--
Total derivative liabilities– long-term	$	17,364	$	13,047

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The following table presents gains (losses) recorded in other comprehensive income (loss) for cash flow hedges associated with our interest rate risk, commodity risk and foreign currency risk hedging portfolios for the periods indicated (dollars in thousands). These amounts do not present the corresponding gains (losses) attributable to the underlying hedged items.

	For the Year Ended December 31,
	2008			2007			2006
Interest Rate Risk Hedging Portfolio:
Parent Company:
Losses on cash flow hedges	$	(21,178	)	$	(9,284	)	$	--
Reclassification of cash flow hedge amounts to net income, net		6,610			(742	)		--
Enterprise Products Partners (excluding Duncan Energy Partners):
Gains (losses) on cash flow hedges		(20,772	)		17,996			11,196
Reclassification of cash flow hedge amounts to net income, net		(4,409	)		(5,429	)		(4,234	)
Duncan Energy Partners:
Losses on cash flow hedges		(7,989	)		(3,271	)		--
Reclassification of cash flow hedge amounts to net income, net		2,008			(350	)		--
TEPPCO:
Losses on cash flow hedges		(26,802	)		(23,604	)		(248	)
Reclassification of cash flow hedge amounts to net income, net		4,924			(64	)		--
Total interest rate risk hedging gains (losses), net		(67,608	)		(24,748	)		6,714
Commodity Risk Hedging Portfolio:
Enterprise Products Partners:
Natural gas marketing activities:
Gains (losses) on cash flow hedges		(30,642	)		(3,125	)		(1,034	)
Reclassification of cash flow hedge amounts to net income, net		30,175			3,299			1,327
NGL and petrochemical operations:
Gains (losses) on cash flow hedges		(120,223	)		(22,735	)		9,975
Reclassification of cash flow hedge amounts to net income, net		28,232			4,564			(13,891	)
TEPPCO:
Gains (losses) on cash flow hedges		(19,257	)		(21,036	)		991
Reclassification of cash flow hedge amounts to net income, net		37,898			1,654			(261	)
Total commodity risk hedging losses, net		(73,817	)		(37,379	)		(2,893	)
Foreign Currency Risk Hedging Portfolio:
Gains on cash flow hedges		9,287			1,308			--
Total foreign currency risk hedging gains, net		9,287			1,308			--
Total cash flow hedge amounts in other comprehensive income (loss)	$	(132,138	)	$	(60,819	)	$	3,821

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The following information summarizes the principal elements of our interest rate risk, commodity risk and foreign currency risk hedging programs. For amounts recorded in net income and other comprehensive income (loss) and on our balance sheet related to our consolidated hedging activities, please refer to the preceding tables.

Interest Rate Risk Hedging Portfolio

The following information summarizes significant components of our interest rate risk hedging portfolio:

Parent Company. The Parent Company’s interest rate exposure results from its variable interest rate borrowings under its credit facility. A portion of the Parent Company’s interest rate exposure is managed by utilizing interest rate swaps and similar arrangements, which effectively convert a portion of its variable rate debt into fixed rate debt. As presented in the following table, the Parent Company had four interest rate swap agreements outstanding at December 31, 2008 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
Parent Company variable-rate borrowings	2	Aug. 2007 to Aug. 2009	Aug. 2009	4.32% to 5.01%	$250.0 million
Parent Company variable-rate borrowings	2	Sep. 2007 to Aug. 2011	Aug. 2011	4.32% to 4.82%	$250.0 million

(1) Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).

As cash flow hedges, any increase or decrease in fair value (to the extent effective) would be recorded in other comprehensive income and reclassified into net income based on the settlement period hedged. Any ineffectiveness of the cash flow hedge is recorded directly into net income as a component of interest expense. At December 31, 2008 and 2007, the aggregate fair value of the Parent Company’s interest rate swaps was a liability of $26.5 million and $11.8 million, respectively.

The Parent Company expects to reclassify $14.6 million of cumulative net losses from its cash flow hedges into net income (as an increase to interest expense) during 2009.

The following table shows the effect of hypothetical price movements on the estimated fair value (“FV”) of the Parent Company’s interest rate swap portfolio (dollars in millions). 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.

		Swap Fair Value at
Scenario	Resulting Classification	December 31, 2007		December 31, 2008		February 3, 2009
FV assuming no change in underlying interest rates	Liability	$	11.8	$	26.5	$	24.1
FV assuming 10% increase in underlying interest rates	Liability		7.0		25.4		22.9
FV assuming 10% decrease in underlying interest rates	Liability		16.5		27.7		25.3

Enterprise Products Partners. Enterprise Products Partners’ interest rate exposure results from variable and fixed rate borrowings under various debt agreements.

Enterprise Products Partners manages a portion of its interest rate exposure by utilizing interest rate swaps and similar arrangements, which allows it to convert a portion of fixed rate debt into variable rate debt or a portion of variable rate debt into fixed rate debt. At December 31, 2008, Enterprise Products Partners had four interest rate swap agreements outstanding having an aggregate notional value of $400.0 million that were accounted for as fair value hedges. The aggregate fair value of these interest rate swaps at December 31, 2008, was $46.7 million (an asset), with an offsetting increase in the fair value of the underlying debt. There were eleven interest rate swaps outstanding at December 31, 2007 having an aggregate fair value of $12.9 million (an asset).

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The following table shows the effect of hypothetical price movements on the estimated fair value of Enterprise Products Partners’ interest rate swap portfolio and the related change in fair value of the underlying debt at the dates indicated (dollars in millions).

		Swap Fair Value at
Scenario	Resulting Classification	December 31, 2007			December 31, 2008		February 3, 2009
FV assuming no change in underlying interest rates	Asset	$	12.9		$	46.7	$	36.3
FV assuming 10% increase in underlying interest rates	Asset (Liability)		(7.4	)		42.4		31.1
FV assuming 10% decrease in underlying interest rates	Asset		33.1			51.1		41.5

The fair value of the interest rate swaps excludes related hedged amounts Enterprise Products Partners have recorded in earnings. The change in fair value between December 31, 2008 and February 3, 2009 is primarily due to an increase in market interest rates relative to the interest rates used to determine the fair value of our financial instruments at December 31, 2008. The underlying floating LIBOR forward interest rate curve used to determine the February 3, 2009 fair values ranged from approximately 1.3% to 3.8% using 6-month reset periods ranging from February 2008 to March 2014.

Enterprise Products Partners may enter into treasury rate lock transactions (“treasury locks”) to hedge U.S. treasury rates related to its anticipated issuances of debt. Each of Enterprise Products Partners’ treasury lock transactions was designated as a cash flow hedge. Gains or losses on the termination of such instruments are reclassified into net income (as a component of interest expense) using the effective interest method over the estimated term of the underlying fixed-rate debt. At December 31, 2008, Enterprise Products Partners had no treasury lock financial instruments outstanding. At December 31, 2007, the aggregate notional value of Enterprise Products Partners’ treasury lock financial instruments was $600.0 million, which had a total fair value (a liability) of $19.6 million. Enterprise Products Partners terminated a number of treasury lock financial instruments during 2008 and 2007. These terminations resulted in realized losses of $40.4 million in 2008 and gains of $48.8 million in 2007.

Enterprise Products Partners expects to reclassify $1.6 million of cumulative net gains from its interest rate risk cash flow hedges into net income (as a decrease to interest expense) during 2009.

Duncan Energy Partners. At December 31, 2008, Duncan Energy Partners had interest rate swap agreements outstanding having an aggregate notional value of $175.0 million. These swaps were accounted for as cash flow hedges. The purpose of these financial instruments is to reduce the sensitivity of Duncan Energy Partners’ earnings to the variable interest rates charged under its revolving credit facility. The aggregate fair value of these interest rate swaps at December 31, 2008 and 2007 was a liability of $9.8 million and $3.8 million, respectively. Duncan Energy Partners expects to reclassify $6.0 million of cumulative net losses from its interest rate risk cash flow hedges into net income (as an increase to interest expense) during 2009.

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 millions).

		Swap Fair Value at
Scenario	Resulting Classification	December 31, 2007			December 31, 2008			February 3, 2009
FV assuming no change in underlying interest rates	Liability	$	(3.8	)	$	(9.8	)	$	(9.4	)
FV assuming 10% increase in underlying interest rates	Liability		(2.2	)		(9.4	)		(9.0	)
FV assuming 10% decrease in underlying interest rates	Liability		(5.3	)		(10.2	)		(9.8	)

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TEPPCO. TEPPCO’s interest rate exposure results from variable and fixed rate borrowings under various debt agreements. At December 31, 2007, TEPPCO had interest rate swap agreements outstanding having an aggregate notional value of $200.0 million and a fair value (an asset) of $0.3 million. These swap agreements settled in January 2008, and there are currently no swap agreements outstanding. These swaps were accounted for as cash flow hedges.

TEPPCO also utilizes treasury locks to hedge underlying U.S. treasury rates related to its anticipated issuances of debt. At December 31, 2007, the aggregate notional value of TEPPCO’s treasury lock financial instruments was $600.0 million, which had a total fair value (a liability) of $25.3 million. TEPPCO terminated these treasury lock financial instruments during 2008, which resulted in $52.1 million of realized losses. TEPPCO recognized approximately $3.6 million of this loss in interest expense as a result of interest payments hedged under the treasury locks not occurring as forecasted. At December 31, 2008, TEPPCO had no treasury lock financial instruments outstanding.

TEPPCO expects to reclassify $5.8 million of cumulative net losses from its interest rate risk cash flow hedges into net income (as an increase to interest expense) during 2009.

Commodity Risk Hedging Portfolio

Our commodity risk hedging portfolio was impacted by a significant decline in natural gas and crude oil prices during the second half of 2008. As a result of the global recession, commodity prices have continued to be volatile during the first quarter of 2009. We may experience additional losses related to our commodity risk hedging portfolio in 2009.

Enterprise Products Partners. 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 the control of Enterprise Products Partners. In order to manage the price risks associated with such products, Enterprise Products Partners may enter into commodity financial instruments.

The primary purpose of Enterprise Products Partners’ commodity risk management activities is to reduce its 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, Enterprise Products Partners injects natural gas into storage and may utilize hedging instruments to lock in the value of its inventory positions. The commodity financial instruments utilized by Enterprise Products Partners are settled in cash.

We have segregated Enterprise Products Partners’ commodity financial instruments portfolio between those financial instruments utilized in connection with its natural gas marketing activities and those used in connection with its NGL and petrochemical operations.

A significant number of the financial instruments in this portfolio hedge the purchase of physical natural gas. If natural gas prices fall below the price stipulated in such financial instruments, Enterprise Products Partners recognizes a liability for the difference; however, if prices partially or fully recover, this liability would be reduced or eliminated, as appropriate. Enterprise Products Partners’ restricted cash balance at December 31, 2008 was $203.8 million in order to meet commodity exchange deposit requirements and the negative change in the fair value of its natural gas hedge positions.

Natural gas marketing activities

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financial instruments within this portion of the commodity financial instruments portfolio are accounted for using mark-to-market accounting, with a small number accounted for as cash flow hedges. Enterprise Products Partners did not have any cash flow hedges outstanding related to its natural gas marketing activities at December 31, 2008.

The following table shows the effect of hypothetical price movements on the estimated fair value of this component of the overall portfolio at the dates presented (dollars in millions):

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2007			December 31, 2008		February 3, 2009
FV assuming no change in underlying commodity prices	Asset (Liability)	$	(0.3	)	$	6.5	$	13.9
FV assuming 10% increase in underlying commodity prices	Asset (Liability)		(1.4	)		2.7		9.4
FV assuming 10% decrease in underlying commodity prices	Asset		0.7			9.9		18.3

The change in fair value of the instruments between December 31, 2008 and February 3, 2009 is primarily due to a decrease in natural gas prices.

NGL and petrochemical operations

At December 31, 2008 and 2007, the aggregate fair value of those financial instruments utilized in connection with Enterprise Products Partners’ NGL and petrochemical operations were liabilities of $102.1 million and $19.0 million, respectively. Almost all of the financial instruments within this portion of the commodity financial instruments portfolio are accounted for as cash flow hedges, with a small number accounted for using mark-to-market accounting.

Enterprise Products Partners has employed a program to economically hedge a portion of its earnings from natural gas processing in the Rocky Mountain region. This program consists of (i) the forward sale of a portion of Enterprise Products Partners’ expected equity NGL production volumes at fixed prices through 2009 and (ii) the purchase, using commodity financial instruments, of the amount of natural gas expected to be consumed as plant thermal reduction (“PTR”) in the production of such equity NGL volumes. The objective of this strategy is to hedge a level of gross margins (i.e., NGL sales revenues less actual costs for PTR and the gain or loss on the PTR hedge) associated with the forward sales contracts by fixing the cost of natural gas used for PTR, through the use of commodity financial instruments. At December 31, 2008, this hedging program had hedged future expected gross margins (before plant operating expenses) of $483.9 million on 22.5 million barrels of forecasted NGL forward sales transactions extending through 2009.

Our NGL forward sales contracts are not accounted for as financial instruments under SFAS 133 since they meet normal purchase and sale exception criteria; therefore, changes in the aggregate economic value of these sales contracts are not reflected in net income and other comprehensive income until the volumes are delivered to customers. On the other hand, the commodity financial instruments used to purchase the related quantities of PTR (i.e., “PTR hedges”) are accounted for as cash flow hedges; therefore, changes in the aggregate fair value of the PTR hedges are presented in other comprehensive income. Once the forecasted NGL forward sales transactions occur, any realized gains and losses on the cash flow hedges would be reclassified into net income in that period.

Prior to actual settlement, if the market price of natural gas is less than the price stipulated in a commodity financial instrument, Enterprise Products Partners recognizes an unrealized loss in other comprehensive income (loss) for the excess of the natural gas price stated in the hedge over the market price. To the extent that Enterprise Products Partners realizes such financial losses upon settlement of the instrument, the losses are added to the actual cost it has to pay for PTR, which would then be based on the lower market price. Conversely, if the market price of natural gas is greater than the price stipulated in such hedges, Enterprise Products Partners recognizes an unrealized gain in other comprehensive income (loss) for the excess of the market price over the natural gas price stated in the PTR hedge. If realized, the gains on the financial instrument would serve to reduce the actual cost paid for PTR, which would then be based on the higher market price. The net effect of these hedging relationships is that Enterprise Products

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Partners’ total cost of natural gas used for PTR approximates the amount it originally hedged under this program.

Enterprise Products Partners expects to reclassify $114.0 million of cumulative net losses from the cash flow hedges within its NGL and petrochemical operations portfolio into net income (as an increase to operating costs and expenses) during 2009.

The following table shows the effect of hypothetical price movements on the estimated fair value of this component of the overall portfolio at the dates presented (dollars in millions):

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2007			December 31, 2008			February 3, 2009
FV assuming no change in underlying commodity prices	Liability	$	(19.0	)	$	(102.1	)	$	(111.6	)
FV assuming 10% increase in underlying commodity prices	Asset (Liability)		11.3			(94.0	)		(109.2	)
FV assuming 10% decrease in underlying commodity prices	Liability		(49.2	)		(110.1	)		(114.1	)

The change in fair value of the NGL and petrochemical portfolio between December 31, 2008 and February 3, 2009 is primarily due to a decrease in natural gas prices.

TEPPCO. As part of its crude oil marketing business, TEPPCO enters into financial instruments such as crude oil swaps. The purpose of such hedging activity is to either balance TEPPCO’s inventory position or to lock in a profit margin. The fair value of the open positions at December 31, 2008 and 2007 was an asset of $3 thousand and a liability of $18.9 million, respectively. At December 31, 2008, TEPPCO had no commodity financial instruments that were accounted for as cash flow hedges. At December 31, 2007, TEPPCO had a limited number of commodity financial instruments that were accounted for as cash flow hedges. TEPPCO has some commodity financial instruments that do not qualify for hedge accounting. These financial instruments had a minimal impact on TEPPCO’s earnings.

The following table shows the effect of hypothetical price movements on the estimated fair value of this portfolio at the dates indicated (dollars in millions):

		Portfolio Fair Value at
Scenario	Resulting Classification	December 31, 2007			December 31, 2008 (1)		February 3, 2009
FV assuming no change in underlying commodity prices	Asset (Liability)	$	(18.9	)	$	--	$	0.2
FV assuming 10% increase in underlying commodity prices	Asset (Liability)		(33.6	)		--		0.2
FV assuming 10% decrease in underlying commodity prices	Asset (Liability)		(4.2	)		--		0.2

(1) Amounts were minimal at December 31, 2008

Foreign Currency Hedging Program – Enterprise Products Partners

Enterprise Products Partners is exposed to foreign currency exchange rate risk through a Canadian NGL marketing subsidiary. As a result, Enterprise Products Partners could be adversely affected by fluctuations in the foreign currency exchange rate between the U.S. dollar and the Canadian dollar. Enterprise Products Partners attempts to hedge this risk using foreign exchange purchase contracts to fix the exchange rate. Mark-to-market accounting is utilized for these contracts, which typically have a duration of one month. For the year ended December 31, 2008, Enterprise Products Partners recorded minimal gains from these financial instruments.

In addition, Enterprise Products Partners is exposed to foreign currency exchange rate risk through its Japanese Yen Term Loan Agreement (“Yen Term Loan”) that EPO entered into in November 2008. As a result, Enterprise Products Partners could be adversely affected by fluctuations in the foreign currency exchange rate between the U.S. dollar and the Japanese yen. Enterprise Products Partners hedged this risk by entering into a foreign exchange purchase contract to fix the exchange rate. This purchase contract was

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designated as a cash flow hedge. At December 31, 2008, the fair value of this contract was $9.3 million (an asset). This contract will be settled in March 2009 upon repayment of the Yen Term Loan.

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.

Fair Value Information

On January 1, 2008, we adopted the provisions of SFAS 157 that apply to financial assets and liabilities. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. See Note 8 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding fair value disclosures pertaining to our financial assets and liabilities.

Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss) primarily includes the effective portion of the gain or loss on financial instruments designated and qualified as a cash flow hedge, foreign currency adjustments and Dixie’s minimum pension liability adjustments. Amounts accumulated in other comprehensive income (loss) from cash flow hedges are reclassified into earnings in the same period(s) in which the hedged forecasted transactions (such as a forecasted forward sale of NGLs) affect earnings. If it becomes probable that the forecasted transaction will not occur, the net gain or loss in accumulated other comprehensive income (loss) must be immediately reclassified.

The following table presents the components of accumulated other comprehensive loss at the balance sheet dates indicated (dollars in thousands):

	At December 31,
	2008			2007
Commodity financial instruments – cash flow hedges	$	(114,087	)	$	(40,271	)
Interest rate financial instruments – cash flow hedges		(66,560	)		1,048
Foreign currency cash flow hedges		10,594			1,308
Foreign currency translation adjustment		(1,301	)		1,200
Pension and postretirement benefit plans		(751	)		588
Proportionate share of other comprehensive loss of
unconsolidated affiliates, primarily Energy Transfer Equity		(13,723	)		(3,848	)
Total accumulated other comprehensive loss	$	(185,828	)	$	(39,975	)

The following table summarizes the components of other comprehensive income (loss) for the periods indicated (dollars in thousands):

	For Year Ended December 31,
	2008			2007			2006
Other comprehensive income (loss):
Cash flow hedges	$	(132,138	)	$	(60,819	)	$	3,821
Change in funded status of pension and postretirement plans, net of tax		(1,339	)		(52	)		--
Proportionate share of other comprehensive loss of unconsolidated affiliates		(9,875	)		(3,848	)		--
Foreign currency translation adjustment		(2,501	)		2,007			(807	)
Total other comprehensive income (loss)	$	(145,853	)	$	(62,712	)	$	3,014

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Item 8. Financial Statements and Supplementary Data.

Our consolidated financial statements, together with the independent registered public accounting firm’s report of Deloitte & Touche LLP begin on page F-1 of this annual report.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

As of the end of the period covered by this Report, our management carried out an evaluation, with the participation of our general partner’s principal executive officer (the “CEO”) and our general partner’s principal financial officer (the “CFO”), of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Securities Exchange Act of 1934. Based on this evaluation, as of the end of the period covered by this Report, the CEO and CFO concluded:

(i)

that our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate to allow timely decisions regarding required disclosure; and

(ii)	that our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting

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 2008, 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.

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING AS OF DECEMBER 31, 2008

The management of Enterprise GP Holdings 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 GP Holdings’ 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 GP Holdings’ internal control over financial reporting as of December 31, 2008. 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 a review of the design 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, 2008, Enterprise GP Holdings’ 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 GP Holdings’ 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 GP Holdings’ 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 within this Item 9A.

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 March 2, 2009.

/s/ Dr. Ralph S. Cunningham		/s/ W. Randall Fowler
Name:	Dr. Ralph S. Cunningham	Name:	W. Randall Fowler
Title:	Chief Executive Officer of	Title:	Chief Financial Officer of
	our general partner,		our general partner,
	EPE Holdings, LLC		EPE Holdings, LLC

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of EPE Holdings, LLC and

Unitholders of Enterprise GP Holdings L.P.

Houston, Texas

We have audited the internal control over financial reporting of Enterprise GP Holdings L.P. and subsidiaries (the "Company") as of December 31, 2008, 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, 2008. 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, 2008, 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 consolidated statements of operations, cash flows, and partners’ equity as of and for the year ended December 31, 2008 of the Company and our report dated March 2, 2009 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 2, 2009

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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 the ASA under the direction of the Board of Directors (the “Board”) and executive officers of EPE Holdings. For a description of the ASA, see “EPCO Administrative Services Agreement” in Note 17 of the Notes to the Consolidated Financial Statements included under Item 8 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 EPE Holdings. Dan L. Duncan, through his indirect control of EPE Holdings, 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 current employees of EPCO who served as directors of EPE Holdings during 2008 were Dan L. Duncan, Randa D. Williams, Dr. Ralph S. Cunningham, Richard H. Bachmann and W. Randall Fowler.

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, EPE Holdings 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 EPE Holdings. Whenever possible, EPE Holdings 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.

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. 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 EPE Holdings or us (either directly or as a partner, unitholder or officer of an organization that has a material relationship with EPE Holdings or us). Based on the foregoing, the Board has affirmatively determined that Charles E. McMahen, Edwin E. Smith, and Thurmon Andress are “independent” directors under the NYSE rules.

Code of Conduct and Ethics and Corporate Governance Guidelines

EPE Holdings 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.

In addition, EPE Holdings has adopted a code of ethics, the “Code of Ethical Conduct for Senior Financial Officers and Managers,” that applies to the CEO, CFO, principal accounting officer and senior financial and other managers. In addition to other matters, this code of ethics establishes policies 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 violations of the code.

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Governance guidelines, together with applicable committee charters, provide the framework for effective governance. The Board has adopted the “Governance Guidelines of Enterprise GP Holdings,” which address several matters, including qualifications for directors, responsibilities of directors, retirement of directors, the composition and responsibilities of the ACG Committee, the conduct and frequency of Board and committee meetings, management succession plans, 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, it will review the Governance Guidelines of Enterprise GP Holdings annually or more often as deemed necessary.

We provide investors access to current information relating to our governance procedures and principles, including the Code of Ethical Conduct for Senior Financial Officers and Managers, the Governance Guidelines of Enterprise GP Holdings and other matters, through our Internet website, www.enterprisegp.com. You may also contact us 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 serve on the ACG Committee. The members of the ACG Committee are independent directors, free from any relationship with us or any of our affiliates or 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.

At December 31, 2008, the members of the ACG Committee are Messrs. McMahen, Smith and Andress. Mr. McMahen is the chairman of ACG Committee. Our Board has determined that Mr. McMahen satisfies the definition of “audit committee financial expert” as defined in Item 407(d) of Regulation S-K promulgated by the SEC.

The ACG Committee’s duties are addressing audit and conflicts-related items and general corporate governance matters. From an audit and conflicts standpoint, the primary responsibilities of the ACG Committee include:

§	monitoring the integrity of our financial reporting process and related systems of internal control;

§	ensuring our legal and regulatory compliance and that of EPE Holdings;

§	overseeing the independence and performance of our independent public accountants;

§	approving all services performed by our independent public accountants;

§	providing for an avenue of communication among the independent public accountants, management, internal audit function and the Board;

§	encouraging adherence to and continuous improvement of our policies, procedures and practices at all levels; and

§	reviewing areas of potential significant financial risk to our businesses.

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 EPE Holdings or the Board of any duties it may owe us or our unitholders.

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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 primary responsibilities of the ACG Committee are to (i) develop and maintain governance guidelines for the Board; (ii) interview possible candidates for Board membership; and (iii) communicate with the Board regarding formats and procedures pertaining to Board meetings.

A copy of the ACG Committee charter is available on our Internet website, www.enterprisegp.com. You may also contact our investor relations department at (866) 230-0745 for a printed copy of this document free of charge.

NYSE Corporate Governance Listing Standards

On March 4, 2008, Dr. Ralph S. Cunningham, our Chief Executive Officer, 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 March 4, 2008.

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. McMahen.

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 EPE Holdings

The following table sets forth the name, age and position of each of the directors and executive officers of EPE Holdings at March 2, 2009.

Name	Age	Position with EPE Holdings
Dan L. Duncan (1)	76	Director and Chairman
Dr. Ralph S. Cunningham (1)	68	Director, President and Chief Executive Officer
W. Randall Fowler (1)	52	Director, Executive Vice President and Chief Financial Officer
Richard H. Bachmann (1)	56	Director, Executive Vice President, Chief Legal Officer and Secretary
Randa Duncan Williams	47	Director
O. S. Andras	73	Director
Charles E. McMahen (2,3)	69	Director
Edwin E. Smith (2)	77	Director
Thurmon Andress (2)	75	Director
William Ordemann (1)	49	Executive Vice President and Chief Operating Officer
Michael J. Knesek (1)	54	Senior Vice President, Controller and Principal Accounting Officer

(1) Executive officer (2) Member of ACG Committee (3) Chairman of ACG Committee

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The following information summarizes the business experience of the directors and executive officers of EPE Holdings who were serving in such capacity at December 31, 2008.

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 alongside his daughter, Ms. Randa Duncan Williams, also a Director of EPE Holdings. He also serves as an Honorary Trustee of the Board of Trustees of the Texas Heart Institute at Saint Luke’s Episcopal Hospital.

Dr. Ralph S. Cunningham. Dr. Cunningham was elected a Director of EPGP in February 2006, having previously 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 its Interim President and Chief Executive Officer from June 2007 to August 2007. Dr. Cunningham was elected a Director and the 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, having previously served as a Director of EPCO 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 served as its President and Chief Executive Officer from 1995 to 1997.

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 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. Mr. Fowler has also served as a Director of EPGP and of EPE Holdings since February 2006 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 and the 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 EPO’s general partner since December 2003 and as an Executive Vice President and the Chief Legal Officer and Secretary of EPE Holdings since August 2005.

Mr. Bachmann was elected a Group Vice Chairman and the 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 elected 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, Conflicts and Nominating and Governance Committees of Constellation Energy Partners LLC.

Randa Duncan Williams. Ms. Williams was elected a Director of EPE Holdings in May 2007. Ms. Duncan is a daughter of Dan L. Duncan and a Director of EPCO. Prior to joining EPCO in 1994, Ms. Williams practiced law with the firms Butler & Binion and Brown, Sims, Wise & White. She currently

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serves on the boards of directors of Encore Bancshares and Encore Bank and also serves on the board of trustees for numerous charitable organizations.

O. S. Andras. Mr. Andras was elected a Director of EPE Holdings in February 2007, having served as a Director of EPGP from April 1998 to February 2006. Mr. Andras served as the Vice Chairman of EPGP from September 2004 to July 2005 and as the Chief Executive Officer of EPGP from April 1998 to February 2005. Mr. Andras served as President of EPGP from April 1998 until September 2004. He served as President and Chief Executive Officer of EPCO from 1996 to February 2001.

Charles E. McMahen. Mr. McMahen was elected a Director of EPE Holdings in August 2005 and serves as Chairman of its ACG Committee. Mr. McMahen served as Vice Chairman of Compass Bank from March 1999 until December 2003 and served as Vice Chairman of Compass Bancshares from April 2001 until his retirement in December 2003. Mr. McMahen also served as Chairman and Chief Executive Officer of Compass Banks of Texas from March 1990 until March 1999. Mr. McMahen has served as a Director of Compass Bancshares since 2001. Mr. McMahen serves on the Board of Directors and Executive Committee of the Greater Houston Partnership. He also served as chairman of the Board of Regents of the University of Houston from September 1998 to August 2000.

Edwin E. Smith. Mr. Smith was elected a Director of EPE Holdings in August 2005 and is a member of its ACG Committee. Mr. Smith has been a private investor since he retired from Allied Bank of Texas in 1989 after a 31-year career in banking. Mr. Smith serves as a Director of Encore Bank and previously served as a director of EPCO from 1987 until 1997.

Thurmon Andress. Mr. Andress was elected a Director of EPE Holdings in November 2006 and is a member of its ACG Committee. Mr. Andress serves as the Managing Director – Houston for Breitburn Energy Company L.P. and is also a member of its Board of Directors. In 1990, he founded Andress Oil & Gas Company, serving as its President and Chief Executive Officer until it merged with Breitburn Energy Company L.P. in 1998. In 1982, he founded Bayou Resources, Inc. a publicly traded energy company that was sold in 1987. Since 2002, Mr. Andress has been a member of the Board of Directors of Edge Petroleum Corp. and currently serves on its Governance and Compensation Committees. Mr. Andress is currently a member of the National Petroleum Council and on the Board of Governors of Houston for the Independent Petroleum Association of America. In 1993, Mr. Andress was inducted into All American Wildcatter’s, a 100-member organization dedicated to American oil and gas explorationists and producers. Beginning in 2008, Mr. Andress will also serve on the Board of the Natural Gas Council.

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 Enterprise Products Partners in connection with its purchase of certain midstream energy assets from affiliates of Shell Oil Company in 1999. Prior to joining Enterprise Products Partners, 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.

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, of EPE Holdings since August 2005 and of 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, EPE Holdings, directors and executive officers of EPE Holdings, certain other officers, and any persons holding more than 10.0% of the Parent Company’s Units are required to report their beneficial ownership of Units and any changes in their beneficial ownership levels to the Parent Company and the SEC. Specific due dates for these reports have been established by

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regulation, and the Parent Company is required to disclose in this annual report any failure to file this information within the specified timeframes. With the exception of the following late filings, all such reporting was done in a timely manner in 2008.

On February 20, 2008, EPCO formed Enterprise Unit L.P. (“Enterprise Unit”) to serve as an incentive arrangement for certain employees of EPCO through a profits interest in Enterprise Unit. Form 4 filings related to beneficial ownership changes in connection with the creation of Enterprise Unit for Richard H. Bachmann, Dr. Ralph S. Cunningham, W. Randall Fowler, Michael J. Knesek and William Ordemann were filed on February 27, 2008, but were due on February 26, 2008. Also, two transactions by Mr. McMahen from 2006 were reported on a Form 4 filing made on February 27, 2009. In addition, beneficial ownership of certain holdings attributed to Randa Duncan Williams that should have been reported on her initial Form 3 were reported on February 27, 2009 on an amended Form 3.

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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 ASA (see Item 13 of this annual report).

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, 2008, 2007 and 2006 for our CEO, CFO and three other most highly compensated executive officers as of December 31, 2008.

Our Named Executive Officers include certain executive officers of our wholly-owned subsidiaries and EPGP. The executive officers of EPGP routinely perform policy-making functions that determine the success of our business strategy. 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 the ASA, 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	($)		($) (2)		($) (3)		($) (4)		($) (5)		($)

Dr. Ralph S. Cunningham (CEO) (1)	2008	$	408,188	$	255,000	$	670,499	$	62,318	$	107,482	$	1,503,487
	2007		398,813		242,250		327,799		33,345		53,626		1,055,833
	2006		478,667		250,000		52,815		13,707		33,208		828,397

W. Randall Fowler (CFO)	2008		254,375		175,000		515,818		41,854		83,528		1,070,575
	2007		258,495		157,320		361,375		30,359		64,791		872,340
	2006		237,463		77,000		191,262		15,666		44,188		565,579

Michael A. Creel (6)	2008		563,200		552,000		1,115,948		90,902		200,241		2,522,291
	2007		399,893		403,830		572,203		49,127		119,387		1,544,440
	2006		336,600		137,500		333,984		25,975		78,521		912,580

A. J. Teague	2008		558,333		500,000		1,005,532		102,783		176,651		2,343,299
	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	2008		447,125		297,500		923,131		71,948		165,354		1,905,058
	2007		378,408		229,338		559,941		48,075		121,149		1,336,911
	2006		236,560		100,000		242,898		18,891		60,935		659,284

(1) Dr. Cunningham was appointed our Chief Executive Officer effective August 1, 2007. (2) Amounts represent discretionary annual cash awards accrued with respect to the years presented. Cash awards are paid in February of the following year (e.g., the cash awards for 2008 were paid in February 2009). (3) Amounts represent expense recognized in accordance with SFAS 123(R) with respect to restricted unit awards issued under the EPCO 1998 Plan and Employee Partnership profits interests awards. (4) Amounts represent expense recognized in accordance with SFAS 123(R) with respect to unit options issued under the EPCO 1998 Plan and EPD 2008 LTIP. (5) Amounts primarily represent (i) matching contributions under funded, qualified, defined contribution retirement plans, (ii) quarterly distributions paid on incentive plan awards and (iii) the imputed value of life insurance premiums paid on behalf of the officer. (6) Mr. Creel served as our Chief Executive Officer until July 31, 2007.

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Compensation Discussion and Analysis

With respect to our Named Executive Officers, compensation paid or awarded by us for the last three fiscal years reflects only that portion of compensation paid by EPCO allocated to us pursuant to the ASA, 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 of our general partner. Equity awards under EPCO’s long-term incentive plans are approved by the ACG Committee of the respective issuer. 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 three years ended December 31, 2008, 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 three years ended December 31, 2008, 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 CEO and the senior vice president of Human Resources for EPCO formulate preliminary compensation recommendations for all of the Named Executive Officers other than our CEO. Mr. Duncan, after consulting with the senior vice president of Human Resources for EPCO, independently makes compensation decisions with respect to our Named Executive Officers. In making these compensation decisions, EPCO considers market data for determining relevant compensation levels and compensation program elements through the review of and, in certain cases, participation in, relevant compensation surveys and reports. These surveys and reports are conducted and prepared by a third party compensation consultant.

Periodically, EPCO will engage a third party consultant to review compensation elements provided to our executive officers. In 2006, EPCO engaged Towers Perrin to review executive compensation relative to our industry. Towers Perrin provided comparative market data on compensation practices and programs for executive level positions based on an analysis of industry competitors. Neither we nor EPCO, which engages the consultant, are aware of the identity of the component companies who supply data to the consultant. EPCO uses the data provided in the Towers Perrin analysis to gauge whether compensation levels reported by the consultant are within the general ranges of compensation for EPCO employees in similar positions, but that comparison is only a factor taken into consideration and may or may not impact compensation of our executive officers, for which Dan L. Duncan has the ultimate decision-making authority. EPCO does not otherwise engage in benchmarking executive level positions.

Mr. Duncan and EPCO do not use any formula or specific performance-based criteria for our Named Executive Officers in connection with determining compensation for services performed for us; rather, Mr. Duncan and EPCO determine an appropriate level and mix of compensation on a case-by-case basis. Further, there is no established policy or target for the allocation between either cash and non-cash or short-term and long-term incentive compensation. However, some considerations that Mr. Duncan may take into account in making the case-by-case compensation determinations include total value of wealth accumulated and the appropriate balance of internal pay equity among executive officers. Mr. Duncan and

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EPCO also consider individual performance, levels of responsibility, skills and experience. All compensation determinations are discretionary and, as noted above, subject to Mr. Duncan’s ultimate decision-making authority except for equity awards under EPCO’s long-term incentive plans, as discussed below.

We believe the absence of specific performance-based criteria associated with our salary compensation and equity awards, and the long-term nature of our equity awards, has the effect of not encouraging excessive risk taking by our executive officers in order to reach certain targets. Further, the practice of making compensation decisions on a case-by-case basis permits consideration of flexible criteria, including current overall market conditions. Because our 2008 annual base salaries and the majority of our 2008 equity awards were made in the first half of 2008, recent market volatility and market declines did not have a material impact on 2008 compensation decisions. However, current market conditions may impact 2009 compensation decisions regarding annual base salaries and equity award grants.

The discretionary cash awards paid to each of our Named Executive Officers were determined by consultation among Mr. Duncan, our CEO 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 in February of each year.

The incentive awards granted under EPCO’s long-term incentive plans to our Named Executive Officers were determined by consultation among Mr. Duncan, our CEO and the senior vice president of Human Resources for EPCO. Incentive awards issued under EPCO’s long-term incentive plans involving securities of Enterprise Products Partners are also approved by the ACG Committee of EPGP. 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 the Employee Partnerships to our Named Executive Officers. See “Summary of Long-Term Incentive Arrangements Underlying 2008 Award Grants” within this Item 11 for information regarding the long-term incentive plans. See Notes 2 and 6 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding the accounting for such awards.

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 three years ended December 31, 2008.

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. In addition, we do not directly employ or compensate our Named Executive Officers. Rather, under the ASA 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

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made by Mr. Duncan and EPCO alone (except for equity awards, as previously noted), and not by our Board.

In light of the foregoing, the Board has reviewed and discussed the Compensation Discussion and Analysis with management and determined that the Compensation Discussion and Analysis be included in the Company’s annual report on Form 10-K for the year ended December 31, 2008.

Submitted by:	Dan L. Duncan
	Dr. Ralph S. Cunningham
	Richard H. Bachmann
	W. Randall Fowler
	Randa Duncan Williams
	O.S. Andras
	Charles E. McMahen
	Edwin E. Smith
	Thurmon Andress

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 2008

The following table presents information concerning grants of plan-based awards to the Named Executive Officers in 2008. The restricted unit and unit option awards granted during 2008 were under the EPCO 1998 Plan and EPD 2008 LTIP. See “Summary of Long-Term Incentive Arrangements Underlying 2008 Award Grants” within this Item 11 for additional information regarding the long-term incentive plans under which these awards were granted.

						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)
Dr. Ralph S. Cunningham (CEO)	5/22/08	--	28,100	--	--	$	651,850
W. Randall Fowler (CFO)	5/22/08	--	28,100	--	--	$	434,537
Michael A. Creel	5/22/08	--	40,000	--	--	$	989,760
A.J. Teague	5/22/08	--	28,100	--	--	$	869,133
Richard H. Bachmann	5/22/08	--	28,100	--	--	$	608,393
Unit option awards: (3)
Dr. Ralph S. Cunningham (CEO)	5/22/08	--	60,000	--	$30.93	$	107,100
W. Randall Fowler (CFO)	5/22/08	--	60,000	--	$30.93	$	71,400
Michael A. Creel	5/22/08	--	90,000	--	$30.93	$	171,360
A.J. Teague	5/22/08	--	60,000	--	$30.93	$	142,800
Richard H. Bachmann	5/22/08	--	60,000	--	$30.93	$	99,960
Profits interest awards: (4)
Enterprise Unit:
Dr. Ralph S. Cunningham (CEO)	2/20/08	--	--	--	--	$	305,357
W. Randall Fowler (CFO)	2/20/08	--	--	--	--	$	161,598
Michael A. Creel	2/20/08	--	--	--	--	$	586,622
A.J. Teague	2/20/08	--	--	--	--	$	407,143
Richard H. Bachmann	2/20/08	--	--	--	--	$	223,929
EPCO Unit:
Dr. Ralph S. Cunningham (CEO)	11/13/08	--	--	--	--	$	1,049,905
W. Randall Fowler (CFO)	11/13/08	--	--	--	--	$	699,937
Michael A. Creel	11/13/08	--	--	--	--	$	1,119,899
A.J. Teague	11/13/08	--	--	--	--	$	1,399,873
Richard H. Bachmann	11/13/08	--	--	--	--	$	979,911

(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 2008. 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 2008, we recognized a total of $0.5 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 2008, we recognized a total of $0.1 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. (4) For the period in which the profits interest awards were outstanding during 2008, we recognized a total of $0.3 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 presented in the table are based on certain assumptions and considerations made by management. See Note 6 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for additional information regarding our fair value assumptions.

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Summary of Long-Term Incentive Arrangements Underlying 2008 Award Grants

The following information summarizes the types of awards granted to our Named Executive Officers during the year ended December 31, 2008. For detailed information regarding our accounting for equity awards, see Note 6 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

As used in the context of the EPCO, the term “restricted unit” represents a time-vested unit under SFAS 123(R). Such awards are non-vested until the required service period expires.

EPCO 1998 Plan. The EPCO 1998 Plan provides for incentive awards to EPCO’s key employees who perform management, administrative or operational functions for us or our affiliates. Awards granted under the EPCO 1998 Plan may be in the form of unit options, restricted units, phantom units and distribution equivalent rights (“DERs”).

When issued, the exercise price of each option grant is equivalent to the market price per unit of Enterprise Products Partners’ common units on the date of grant. In general, options granted under the EPCO 1998 Plan have a vesting period of four years and remain exercisable for ten years from the date of grant.

A total of 152,400 restricted units were granted under this plan to the Named Executive Officers in May 2008. Restricted unit awards under the EPCO 1998 Plan allow recipients to acquire common units of Enterprise Products Partners (at no cost to the recipient) once a defined vesting period expires, subject to certain forfeiture provisions. The restrictions on such awards generally lapse four years from the date of grant. The fair value of restricted units is based on the market price per unit of Enterprise Products Partners’ 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 Enterprise Products Partners to its unitholders.

The EPCO 1998 Plan also provides for the issuance of phantom unit awards, including related DERs. No phantom unit awards or associated DERs have been granted under the EPCO 1998 Plan.

EPD 2008 LTIP. The EPD 2008 LTIP provides for incentive awards to EPCO’s key employees who perform management, administrative or operational functions for us or our affiliates. Awards granted under the EPD 2008 LTIP may be in the form of unit options, restricted units, phantom units and DERs.

A total of 330,000 options were granted under this plan to the Named Executive Officers in May 2008. When issued, the exercise price of each option grant was equivalent to the market price per unit of Enterprise Products Partners’ common units on the date of grant. In general, these options have a vesting period of four years and are exercisable during specified periods within the calendar year immediately following the year in which vesting occurs. At December 31, 2008, no restricted units, phantom units or DERs had been issued under this plan.

Profits interests awards. Our Named Executive Officers were granted awards consisting of profits interests, or Class B limited partner interests, in Enterprise Unit in February 2008 and EPCO Unit in November 2008. In addition, the Named Executive Officers have received profits interests awards in the other Employee Partnerships in prior years. Profits interest awards entitle each holder to participate in the expected long-term appreciation in value of the equity securities owned by each Employee Partnership. The Employee Partnerships in which the Named Executive Officers participate own either Parent Company Units or Enterprise Products Partners’ common units or a combination of both. Such awards are subject to forfeiture. For additional information regarding the Employee Partnerships, including the assumptions we used to estimate the fair value of these awards, see Note 6 of the Notes to Financial Statements included under Item 8 of this annual report.

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The following table presents each Named Executive Officer’s share of the total profits interest in the Employee Partnerships at December 31, 2008.

	Percentage Ownership of Class B Interests
	EPE	EPE	EPE	Enterprise	EPCO
Named Executive Officer	Unit I	Unit II	Unit III	Unit	Unit
Dr. Ralph S. Cunningham (CEO)	--	100.0%	7.8%	9.7%	20.0%
W. Randall Fowler (CFO)	5.5%	--	7.8%	7.8%	20.0%
Michael A. Creel	8.2%	--	7.8%	17.5%	20.0%
A.J. Teague	5.5%	--	6.5%	9.7%	20.0%
Richard H. Bachmann	8.2%	--	7.8%	9.7%	20.0%

EPCO 2005 Plan. The EPCO 2005 Plan was established to encourage our independent directors and employees of EPCO that perform services for the Parent Company to increase their ownership of Parent Company Units and to develop a sense of proprietorship and personal involvement in the business and financial success of the Parent Company. This plan provides for the future issuance of unit options, restricted units, phantom units and UARs denominated in the Parent Company’s Units. The maximum number of Units that can be issued under the EPCO 2005 Plan is 250,000. With the exception of 90,000 UARs issued to the independent directors of EPE Holdings, no other awards have been issued under this plan. For information regarding the compensation of our independent directors, see “Director Compensation” within this Item 11.

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Equity Awards Outstanding at December 31, 2008

The following tables present information concerning each Named Executive Officer’s long-term incentive awards outstanding at December 31, 2008. We expect to be allocated our pro rata share of the cost of such awards under the ASA. As a result, the gross amounts listed in the table do not represent the amount of expense we will recognize in connection with these awards.

The following table presents information concerning each Named Executive Officer’s nonvested restricted units and unexercised unit options at December 31, 2008:

		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	(#)	($/Unit)	Date	(#)(2)	($)(3)
Restricted unit awards:
Dr. Ralph S. Cunningham (CEO)	Various (1)	--	--	--	66,600	$1,380,618
W. Randall Fowler (CFO)	Various (1)	--	--	--	63,100	$1,308,063
Michael A. Creel	Various (1)	--	--	--	88,500	$1,834,605
A.J. Teague	Various (1)	--	--	--	76,600	$1,587,918
Richard H. Bachmann	Various (1)	--	--	--	76,600	$1,587,918
Unit option awards:
Dr. Ralph S. Cunningham (CEO):
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	--	--
May 22, 2008 option grant	5/22/12	60,000	30.93	12/31/13	--	--
W. Randall Fowler (CFO):
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	--	--
May 22, 2008 option grant	5/22/12	60,000	30.93	12/31/13	--	--
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	--	--
May 22, 2008 option grant	5/22/12	90,000	30.93	12/31/13	--	--
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	--	--
May 22, 2008 option grant	5/22/12	60,000	30.93	12/31/13	--	--
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	--	--
May 22, 2008 option grant	5/22/12	60,000	30.93	12/31/13	--	--

(1) Of the 371,400 restricted unit awards presented in the table, 36,000 vest in 2009 60,000 vest in 2010, 123,000 vest in 2011 and 152,400 vest in 2012. (2) Amounts represent total number of restricted unit awards granted to Named Executive Officer. (3) Amounts derived by multiplying the total number of restricted unit awards granted to the Named Executive Officer by the closing price of Enterprise Products Partners’ common units at December 31, 2008 of $20.73 per unit.

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The following table presents information concerning each Named Executive Officer’s nonvested profits interest awards at December 31, 2008:

		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:
W. Randall Fowler (CFO)	11/09/12	--	--	--	--	$ 0
Michael A. Creel	11/09/12	--	--	--	--	$ 0
A.J. Teague	11/09/12	--	--	--	--	$ 0
Richard H. Bachmann	11/09/12	--	--	--	--	$ 0
EPE Unit II:
Dr. Ralph S. Cunningham (CEO)	2/10/14	--	--	--	--	$ 0
EPE Unit III:
Dr. Ralph S. Cunningham (CEO)	5/09/14	--	--	--	--	$ 0
W. Randall Fowler (CFO)	5/09/14	--	--	--	--	$ 0
Michael A. Creel	5/09/14	--	--	--	--	$ 0
A.J. Teague	5/09/14	--	--	--	--	$ 0
Richard H. Bachmann	5/09/14	--	--	--	--	$ 0
Enterprise Unit:
Dr. Ralph S. Cunningham (CEO)	2/20/14	--	--	--	--	$ 0
W. Randall Fowler (CFO)	2/20/14	--	--	--	--	$ 0
Michael A. Creel	2/20/14	--	--	--	--	$ 0
A.J. Teague	2/20/14	--	--	--	--	$ 0
Richard H. Bachmann	2/20/14	--	--	--	--	$ 0
EPCO Unit:
Dr. Ralph S. Cunningham (CEO)	11/13/13	--	--	--	--	$ 0
W. Randall Fowler (CFO)	11/13/13	--	--	--	--	$ 0
Michael A. Creel	11/13/13	--	--	--	--	$ 0
A.J. Teague	11/13/13	--	--	--	--	$ 0
Richard H. Bachmann	11/13/13	--	--	--	--	$ 0

The profits interest awards had no market (or assumed liquidation) value at December 31, 2008 due to a decrease in the market value of the limited partner interests owned by each Employee Partnership since the formation.

Option Exercises and Stock Vested Table

The following table presents the exercise of unit options by and vesting of restricted units to our Named Executive Officers during the year ended December 31, 2008 for which we were historically responsible for a share of the related cost of such awards.

	Option Awards		Unit Awards
	Number of		Number of	Gross
	Units	Value	Units	Value
	Acquired on	Realized on	Acquired on	Realized on
	Exercise	Exercise	Vesting	Vesting
Name	(#)	($)	(#)	($) (1)
W. Randall Fowler (CFO)	--	--	23,777	$467,209
Michael A. Creel	--	--	54,553	$1,146,990
A.J. Teague	--	--	12,000	$364,440
Richard H. Bachmann	--	--	54,553	$1,146,990

(1) Amount determined by multiplying the number of restricted unit awards that vested during 2008 by the closing price of Enterprise Products Partners’ common units on the date of vesting.

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No options were exercised by the Named Executive Officers during 2008. Also, Dr. Cunningham had no awards vest during 2008.

Nonqualified Deferred Compensation for the 2008 Fiscal Year

During 2008, no Named Executive Officer received deferred compensation (other than incentive awards described elsewhere) on a basis that was not tax-qualified with respect to any defined contribution or other plan.

Director Compensation

The following table presents information regarding compensation to the independent directors of our general partner during 2008.

	Fees Earned		Unit
	or Paid	Unit	Appreciation
	in Cash	Awards	Rights	Total
Name	($)	($)	($) (1)	($)
Charles E. McMahen	$90,000	--	$(7,979)	$82,021
Edwin E. Smith	$75,000	--	$(7,979)	$67,021
Thurmon Andress	$75,000	--	$(5,945)	$69,055

(1) Amounts presented reflect compensation expense recognized in accordance with SFAS 123(R) by EPE Holdings. Expense credits were recognized in 2008 as a result of a decrease in the Parent Company’s Unit prices during the period.

Neither we nor EPE Holdings provide any additional compensation to employees of EPCO who serve as directors of our general partner. The employees of EPCO who served as directors of EPE Holdings during 2008 were Messrs. Duncan, Fowler and Bachmann.

Currently, EPE Holdings’ three independent directors, Messrs. McMahen, Smith, and Andress, are provided cash compensation for their services as follows:

§	Each independent director receives $75 thousand in cash annually.

§	If the individual serves as Chairman of the ACG Committee of the Board of Directors, then he receives an additional $15 thousand in cash annually.

As of December 31, 2008, each of Messrs. McMahen, Smith and Andress have been granted 30,000 UARs under the EPCO 2005 Plan. Of the 90,000 UARs outstanding, 20,000 vest in August 2011 (issued August 2006) and 70,000 vest in November 2011 (issued November 2006). The grant date price of the UARs vesting in August 2011 is $35.71 per Unit. The grant date price of the UARs vesting in November 2011 is $34.10. The UARs entitle the directors to receive an amount in the future equal to the excess, if any, of the fair market value of the Parent Company’s Units (determined as of the future vesting date) over the grant date price per Unit, in Units or cash (at the discretion of EPE Holdings). The UARs are accounted for as liability awards by EPE Holdings since it is management’s current intent to satisfy these obligations with cash. If a director resigns prior to vesting, his UAR awards are forfeited.

At December 31, 2008, the estimated fair value (as determined in accordance with SFAS 123(R)) of the 30,000 UARs granted to each independent director was as follows: Mr. McMahen, $46 thousand; Mr. Smith, $46 thousand; and Mr. Andress, $43 thousand. These estimates were based on the following assumptions: (i) remaining life of award of three years; (ii) risk-free interest rate of 1.0%; (iii) an expected distribution yield on the Parent Company’s Units of 5.4%; and (iv) an expected unit price volatility of the Parent Company’s Units of 30.3%.

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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 2, 2009, regarding each person known by our general partner to beneficially own more than 5.0% of the Parent Company’s Units.

		Amount and
		Nature of
Title of	Name and Address	Beneficial	Percent
Class	of Beneficial Owner	Ownership	of Class
Units	Dan L. Duncan	108,287,968	77.8%
	1100 Louisiana Street, 10th Floor
	Houston, Texas 77002

Security Ownership of Management

The following sets forth certain information regarding the beneficial ownership of the Parent Company’s Units and the common units of Enterprise Products Partners, Duncan Energy Partners and TEPPCO as of February 2, 2009 by:

§	our Named Executive Officers;

§	the current directors of EPE Holdings; and

§	the current directors and executive officers of EPE Holdings as a group.

If an individual does not own any securities in the foregoing registrants, he or she is not listed in the following tables.

Enterprise Products Partners and TEPPCO are subsidiaries of the Parent Company. Duncan Energy Partners is a subsidiary of Enterprise Products Partners.

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. Mr. Duncan owns 50.4% of the voting stock of EPCO and, accordingly, exercises sole voting and dispositive power with respect to the securities beneficially owned by affiliates of EPCO. 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.

Essentially all of the ownership interests in the Parent Company, Enterprise Products Partners and TEPPCO 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 us.

Borrowings under the EPE Revolver, Term Loan A and Term Loan B are secured by the Parent Company’s ownership of (i) 13,454,498 common units of Enterprise Products Partners, (ii) 100% of the membership interests in EPGP, (iii) 38,976,090 common units of Energy Transfer Equity, (iv) 4,400,000 common units of TEPPCO and (v) 100% of the membership interests in TEPPCO GP. See Note 15 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report for information regarding our consolidated debt obligations.

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Parent Company and Enterprise Products Partners

	Parent Company Units					Enterprise Products Partners L.P. Common Units
	Amount and					Amount and
	Nature Of					Nature Of
	Beneficial		Percent			Beneficial		Percent of
Name of Beneficial Owner	Ownership		of Class			Ownership		Class
Dan L. Duncan:
Units owned by EPCO:
Through DFI GP Holdings L.P.		25,162,804		18.1	%		--		--
Through DFI Delaware Holdings L.P.		--		--			121,990,717		27.0	%
Through Duncan Family Interests, Inc.		71,860,405		51.6	%		--		--
Through EPCO Holdings, Inc.		--		--			1,037,037		*
Units owned by DD Securities LLC		3,745,673		2.7	%		487,100		*
Units owned by Employee Partnerships (1)		7,165,315		5.1	%		1,623,654		*
Units owned by Parent Company		--		--			13,670,925		3.0	%
Units owned by family trusts (2)		243,071		*			12,517,338		2.8	%
Units owned personally		110,700		*			1,179,756		*
Total for Dan L. Duncan		108,287,968		77.8	%		152,506,527		33.8	%

Dr. Ralph S. Cunningham (3)		4,000		*			76,847		*
W. Randall Fowler (3)		3,000		*			105,300		*
Michael A. Creel (3)		--		--			195,842		*
A.J. Teague (3)		17,000		*			260,442		*
Richard H. Bachmann (3)		18,698		*			190,822		*
Randa Duncan Williams		75,000		*			--		--
O. S. Andras		178,571		*			1,280,000		*
Charles E. McMahen		10,167		*			--		--
Edwin E. Smith		20,800		*			112,004		*
Thurmon Andress		9,400		*			7,400		*
All current directors and executive officers of EPE Holdings, as a group (11 individuals in total) (4)		108,624,604		78.0	%		154,735,184		34.2	%

* Represents a beneficial ownership of less than 1% of class
(1) As a result of EPCO’s ownership of the general partners of the Employee Partnerships, Mr. Duncan is deemed beneficial owner of the limited partner interests held by these entities. (2) Mr. Duncan is deemed beneficial owner of the limited partner interests 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 115,000 options to acquire Enterprise Products Partners common units that were issued under the EPCO 1998 Plan. These options vested in prior periods and remain exercisable within 60 days of the filing date of this annual report.

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Duncan Energy Partners and TEPPCO

	Duncan Energy Partners L.P. Common Units					TEPPCO Partners, L.P. Common Units
	Amount and					Amount and
	Nature Of					Nature Of
	Beneficial		Percent			Beneficial		Percent of
Name of Beneficial Owner	Ownership		of Class			Ownership		Class
Dan L. Duncan:
Units owned by EPCO:
Through EPO (1)		42,726,987		74.1	%		--		--
Through DFI GP Holdings L.P.		--		--			2,500,000		2.4	%
Through Duncan Family Interests, Inc.		--		--			8,986,711		8.6	%
Units owned by DD Securities LLC		103,100		*			704,564		*
Units owned by Employee Partnerships (2)		--		--			364,565		*
Units owned by Parent Company		--		--			4,400,000		4.2	%
Units owned by family trusts (3)		--		--			53,275		*
Units owned personally		282,500		*			64,200		*
Total for Dan L. Duncan		43,112,587		74.7	%		17,073,315		16.3	%

Dr. Ralph S. Cunningham (4)		3,000		*			--		--
W. Randall Fowler (4)		2,000		*			--		--
Michael A. Creel (4)		7,500		*			--		--
A.J. Teague (4)		6,000		*			--		--
Richard H. Bachmann (4)		10,171		*			--		--
Randa Duncan Williams		--		--			--		--
O. S. Andras		--		--			--		--
Charles E. McMahen		20,000		*			--		--
Edwin E. Smith		29,000		*			5,000		*
Thurmon Andress		3,200		*			--		--
All current directors and executive officers of EPE Holdings, as a group (11 individuals in total)		43,198,609		74.9	%		17,079,315		16.3	%

* Represents a beneficial ownership of less than 1% of class
(1) Amount includes 37,333,887 Class B units of Duncan Energy Partners that converted to common units on a one-to-one basis on February 1, 2009. EPO was issued Class B units as partial consideration for a December 2008 asset dropdown transaction with Duncan Energy Partners. (2) As a result of EPCO’s ownership of the general partners of the Employee Partnerships, Mr. Duncan is deemed beneficial owner of the limited partner interests held by these entities. (3) Mr. Duncan is deemed beneficial owner of the limited partner interests held by certain family trusts, the beneficiaries of which are shareholders of EPCO. (4) These individuals are Named Executive Officers.

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Securities Authorized for Issuance Under Equity Compensation Plans

In November 2005, the Parent Company filed a registration statement covering the potential future issuance of up to 250,000 of its Units in connection with the EPCO 2005 Plan (see Item 11 of this annual report). The following table sets forth certain information as of December 31, 2008 regarding the EPCO 2005 Plan.

				Number of
				Units
				remaining
				available for
				future issuance
		Number of		under equity
		Units to	Weighted-	compensation
		be issued	average	plans (excluding
		upon exercise	exercise price	securities
		of outstanding	of outstanding	reflected in
Plan Category		awards	awards	column (a)
		(a)	(b)	(c)
Equity compensation plans approved by unitholders:
	EPCO 2005 Plan	--	--	160,000
Equity compensation plans not approved by unitholders:
	None.	--	--	--
Total for equity compensation plans		--	--	160,000

The 160,000 Units remaining available for future issuance under the EPCO 2005 Plan assumes that EPE Holdings elects to issue Units to its independent directors when the 90,000 UARs outstanding at December 31, 2008 vest. EPE Holdings has the option of issuing Units or making cash payments when the UARs vest. The EPCO 2005 Plan is effective until the earlier of (i) all available Units under the plan have been issued to participants, (ii) early termination of the EPCO 2005 Plan by EPCO or (iii) the tenth anniversary of the EPCO 2005 Plan, which is August 2015.

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, 2008. 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 part of our consolidated group of companies:

§	EPCO and its consolidated private company subsidiaries;

§	EPE Holdings, our general partner; and

§	the Employee Partnerships.

EPCO is a private company controlled by Dan L. Duncan, who is also a director and Chairman of EPE Holdings and EPGP. At December 31, 2008, EPCO and its private company affiliates beneficially owned 108,287,968 (or 77.8%) of the Parent Company’s outstanding Units and 100% of its general partner,

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EPE Holdings. In addition, at December 31, 2008, EPCO and its affiliates beneficially owned 152,506,527 (or 34.5%) of Enterprise Products Partners’ common units, including 13,670,925 common units owned by the Parent Company. At December 31, 2008, EPCO and its affiliates beneficially owned 17,073,315 (or 16.3%) of TEPPCO’s common units, including the 4,400,000 common units owned by the Parent Company. The Parent Company owns all of the membership interests of EPGP and TEPPCO GP. The principal business activity of EPGP is to act as the sole managing partner of Enterprise Products Partners. The principal business activity of TEPPCO GP is to act as the sole general partner of TEPPCO. The executive officers and certain of the directors of EPGP, TEPPCO GP, and EPE Holdings are employees of EPCO.

The Parent Company, EPE Holdings, TEPPCO, TEPPCO GP, Enterprise Products Partners and EPGP are separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are separate from those of EPCO and its other affiliates. EPCO and its private company subsidiaries depend on the cash distributions they receive from the Parent Company, TEPPCO, Enterprise Products Partners and other investments to fund their other operations and to meet their debt obligations. EPCO and its affiliates received $439.8 million in cash distributions from us during the year ended December 31, 2008.

The ownership interests in Enterprise Products Partners and TEPPCO that are owned or controlled by the Parent Company are pledged as security under its credit facility. In addition, the ownership interests in the Parent Company, Enterprise Products Partners, and TEPPCO that are owned or controlled by EPCO and its affiliates, other than those interests owned by the Parent Company, 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 the Parent Company, Enterprise Products Partners and TEPPCO.

An affiliate of EPCO provides us trucking services for the transportation of NGLs and other products. For the year ended December 31, 2008, Enterprise Products Partners and TEPPCO paid this trucking affiliate $21.7 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, 2008, we paid EPCO $7.8 million for office space leases.

EPCO Administrative Services Agreement. We have no employees. All of our management, administrative and operating functions are performed by employees of EPCO pursuant to an ASA. Enterprise Products Partners and its general partner, the Parent Company and its general partner, Duncan Energy Partners and its general partner, and TEPPCO and its general partner, among other affiliates, 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 business, properties and assets (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, and 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 a named insured in its overall insurance program with the associated premiums and other costs being allocated to us.

Under the ASA, EPCO subleases to Enterprise Products Partners (for $1 per year) certain equipment which it holds pursuant to operating leases and has assigned to Enterprise Products Partners its

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purchase option under such leases (the “retained leases”). EPCO remains liable for the actual cash lease payments associated with these agreements. Enterprise Products Partners records the full value of these payments made by EPCO on Enterprise Products Partners’ behalf as a non-cash related party operating lease expense, with the offset to partners’ equity accounted for as a general contribution to its partnership. Enterprise Products Partners exercised its election under the retained leases to purchase a cogeneration unit in December 2008 for $2.3 million. Should Enterprise Products Partners decide to exercise the purchase option associated with the remaining agreement, it would pay the original lessor $3.1 million in June 2016.

Our operating costs and expenses for the year ended December 31, 2008 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 $451.5 million during the year ended December 31, 2008.

Likewise, our general and administrative costs for the year ended December 31, 2008 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). Such reimbursements were $91.9 million during the year ended December 31, 2008.

Since the vast majority of such expenses are charged to us on an actual basis (i.e. no mark-up or subsidy is charged or received by EPCO), we believe that such expenses are representative of what the amounts would have been on a standalone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.

The ASA also addresses potential conflicts that may arise among parties to the agreement, including (i) Enterprise Products Partners and EPGP; (ii) Duncan Energy Partners and DEP GP; (iii) the Parent Company and EPE Holdings; and (iv) the EPCO Group, which includes EPCO and its affiliates (but does not include the aforementioned entities and their controlled affiliates). The administrative services agreement provides, among other things, that:

If a business opportunity to acquire “equity securities” (as defined) is presented to the EPCO Group; Enterprise Products Partners and EPGP; Duncan Energy Partners and DEP GP; or the Parent Company and EPE Holdings, then the Parent Company 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) and IDRs or similar rights in publicly traded partnerships 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

IDRs and limited partner interests (or securities which have characteristics similar to IDRs or limited partner interests) in publicly traded partnerships or interest 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.

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Holdings. If the purchase price is reasonably likely to be less than such threshold amount, 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 the Parent Company 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 either for it or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan Energy Partners. In the event that Enterprise Products Partners affirmatively directs the opportunity to Duncan Energy Partners, Duncan Energy Partners may pursue such acquisition. Enterprise Products Partners will be presumed to desire 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 of the equity securities, Enterprise Products Partners will follow the same procedures applicable to the Parent Company, as described above but utilizing EPGP’s chief executive officer and ACG Committee. 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, TEPPCO GP or 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, EPGP, EPE Holdings or the Parent Company, then Enterprise Products Partners will have the first right to pursue such opportunity or, if desired by Enterprise Products Partners in its sole discretion, for the benefit of Duncan Energy Partners. Enterprise Products Partners will be presumed to desire to pursue the business opportunity until such time as EPGP advises the EPCO Group, EPE Holdings and DEP GP that Enterprise Products Partners 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 $100.0 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 such threshold amount, the chief executive officer of EPGP may make the determination to decline the business opportunity without consulting EPGP’s ACG Committee. In the event that Enterprise Products Partners affirmatively directs the business opportunity to Duncan Energy Partners, Duncan Energy Partners may pursue such business opportunity. In the event that Enterprise Products Partners abandons the business opportunity for itself and for Duncan Energy Partners and so notifies the EPCO Group, EPE Holdings and DEP GP, the Parent Company will have the second right to pursue such business opportunity, and will be presumed to desire to do so, until such time as EPE Holdings shall have determined to abandon the pursuit of such opportunity in accordance with the procedures described above, and shall have advised the EPCO Group that we have abandoned the pursuit of such acquisition.

In the event that the Parent Company abandons the acquisition and so notifies the EPCO Group, the EPCO Group may either pursue the business opportunity or offer the business opportunity to a private company affiliate of EPCO or TEPPCO and TEPPCO GP without any further obligation to any other party or offer such opportunity to other affiliates.

None of the EPCO Group, EPGP, Enterprise Product Partners, DEP GP, Duncan Energy Partners, EPE Holdings or the Parent Company have any obligation to present business opportunities to TEPPCO or TEPPCO GP. Likewise, TEPPCO and TEPPCO GP have no obligation to present business opportunities to the EPCO Group, EPGP, Enterprise Products Partners, DEP GP, Duncan Energy Partners, EPE Holdings or the Parent Company.

The ASA was amended on January 30, 2009 to provide for the cash reimbursement by TEPPCO, Enterprise Products Partners, Duncan Energy Partners and the Parent Company to EPCO of distributions of

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cash or securities, if any, made by TEPPCO Unit II or EPCO Unit to their respective Class B limited partners. The ASA amendment also extended the term under which EPCO provides services to the partnership entities from December 2010 to December 2013 and made other updating and conforming changes.

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, Enterprise Products Partners’ common units and TEPPCO’s common units. For information regarding the Employee Partnerships, see Note 6 of the Notes to Consolidated Financial Statements included under Item 8 of this annual report.

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:

Enterprise Products Partners sells 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 totaled $362.9 million for the year ended December 31, 2008. In addition, Duncan Energy Partners furnished $1.0 million in letters of credit on behalf of Evangeline at December 31, 2008.

Enterprise Products Partners pays Promix for the transportation, storage and fractionation of NGLs. In addition, Enterprise Products Partners sells natural gas to Promix for its plant fuel requirements. For the year ended December 31, 2008, Enterprise Products Partners recorded revenues of $24.5 million from Promix and paid Promix $38.7 million for its services to us.

§	We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $11.2 million for such services during the year ended December 31, 2008.

§	For the year ended December 31, 2008, TEPPCO paid $1.7 million to Centennial in connection with a pipeline capacity lease. In addition, TEPPCO paid $6.6 million to Centennial in 2008 for other pipeline transportation services.

§	For the year ended December 31, 2008, TEPPCO paid Seaway $6.0 million for transportation and tank rentals in connection with its crude oil marketing activities.

Enterprise Products Partners has a long-term sales contract with a consolidated subsidiary of ETP. In addition, Enterprise Products Partners and another subsidiary of ETP, transport natural gas on each other’s systems and share operating expenses on certain pipelines. A subsidiary of ETP also sells natural gas to Enterprise Products Partners. For the year ended December 31, 2008, we recorded revenues of $561.7 million from Energy Transfer Equity and paid Energy Transfer Equity $192.2 million for its services to us.

Relationship with Duncan Energy Partners

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Energy Partners of approximately $291.0 million. On this same date, Enterprise Products Partners contributed 66.0% of its equity interests in certain of its subsidiaries to Duncan Energy Partners. Enterprise Products Partners retained the remaining 34.0% equity interests in the subsidiaries. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of net proceeds from its initial public offering 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).

On December 8, 2008, Enterprise Products Partners contributed additional equity interests in certain of its subsidiaries to Duncan Energy Partners. As consideration for the contribution, Enterprise Products Partners received $280.5 million in cash and 37,333,887 Class B units of Duncan Energy Partners, having a market value of $449.5 million. The Class B units automatically converted on a one-to-one basis to common units of Duncan Energy Partners on February 1, 2009.

At December 31, 2008, Enterprise Products Partners owned 74.1% of Duncan Energy Partners’ limited partner interests and all of its general partner interest.

Enterprise Products Partners has continued involvement with all of the subsidiaries of Duncan Energy Partners, including the following types of transactions: (i) it utilizes storage services to support its Mont Belvieu fractionation and other businesses; (ii) it buys natural gas from and sells natural gas in connection with its normal business activities; and (iii) it is currently the sole shipper on an NGL pipeline system located in south Texas.

EPCO and its affiliates, including Enterprise Products Partners and TEPPCO, may contribute or sell other equity interests and assets to Duncan Energy Partners. EPCO and its affiliates have no obligation or commitment to make such contributions or sales to Duncan Energy Partners.

Relationship with Cenac

In connection with TEPPCO’s marine services acquisition in February 2008, Cenac and affiliates became a related party of TEPPCO due to its ownership of TEPPCO common units and other considerations. TEPPCO entered into a transitional operating agreement with Cenac in which TEPPCO’s fleet of acquired tow boats and tank barges will continue to be operated by employees of Cenac for a period of up to two years following the acquisition. Under this agreement, TEPPCO pays Cenac a monthly operating fee and reimburses Cenac for personnel salaries and related employee benefit expenses, certain repairs and maintenance expenses and insurance premiums on the equipment. During 2008, TEPPCO paid Cenac approximately $48.3 million in connection with the transitional operating agreement.

Review and Approval of Transactions with Related Parties

We generally consider transactions between us and our subsidiaries, on the one hand, and our executive officers and directors (or their immediate family members), our general partner or its affiliates (including companies owned or controlled by Mr. Duncan such as EPCO), on the other hand, to be related party transactions. As further described below, our partnership agreement sets forth procedures by which related party transactions and conflicts of interest may be approved or resolved by the general partner or the ACG Committee. In addition, our ACG Committee Charter, our general partner’s written internal review and approval policies and procedures, or “management authorization policy,” and the amended and restated ASA with EPCO govern specified related party transactions, as further described below.

The ACG Committee Charter provides that the ACG Committee is established to review and approve related party transactions:

§	for which Board approval is required by our management authorization policy, as such policy may be amended from time to time;

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§	where an officer or director of the general partner or any of our subsidiaries is a party, without regard to the size of the transaction;

§	when requested to do so by management or the Board; or

§	pursuant to our partnership agreement or the limited liability company agreement of the general partner, as such agreements may be amended from time to time.

As discussed in more detail in “Partnership Management,” “Corporate Governance” and “ACG Committee” within Item 10, the ACG Committee is comprised of three directors: Charles E. McMahen, Thurmon Andress and Edwin E. Smith. During the year ended December 31, 2008, the ACG Committee did not review or approve any related party transactions.

Our management authorization policy currently requires board approval for the following types of transactions to the extent such transactions have a value in excess of $100 million, which would trigger ACG Committee review under our ACG Committee Charter if such transaction is also a related party transaction:

§	asset purchase or sale transactions;

§	capital expenditures; and

§	purchase orders and operating and administrative expenses not governed by the ASA.

The ASA governs numerous day-to-day transactions between us and our subsidiaries, our general partner 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, without markup or discount, for those services. The ACG Committee reviewed and recommended the ASA, and the Board approved it upon receiving such recommendation.

Related party transactions that do not occur under the ASA and that are not reviewed by the ACG Committee, as described above, are subject to the management authorization policy. This policy, which applies to related party transactions as well as transactions with unrelated parties, specifies thresholds for our general partner’s officers and chairman of the Board to authorize various categories of transactions, including purchases and sales of assets, expenditures, commercial and financial transactions and legal agreements.

Partnership Agreement Standards for ACG Committee Review

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 to 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;

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§	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.

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.

The review and work performed by the ACG Committee with respect to a transaction varies depending upon the nature of the transaction and the scope of the ACG Committee’s charge. Examples of functions the ACG Committee may, as it deems appropriate, perform in the course of reviewing a transaction include (but are not limited to):

§	assessing the business rationale for the transaction;

§	reviewing the terms and conditions of the proposed transaction, including consideration and financing requirements, if any;

§	assessing the effect of the transaction on our earnings and distributable cash flow per unit, and on our results of operations, financial condition, properties or prospects;

§	conducting due diligence, including by interviews and discussions with management and other representatives and by reviewing transaction materials and findings of management and other representatives;

§	considering the relative advantages and disadvantages of the transactions to the parties;

§	engaging third party financial advisors to provide financial advice and assistance, including by providing fairness opinions if requested;

§	engaging legal advisors; and

§	evaluating and negotiating the transaction and recommending for approval or approving the transaction, as the case may be.

Nothing contained in the partnership agreement requires the ACG Committee to consider the interests of any person other than the partnership. In the absence of bad faith by the ACG Committee or our general partner, the resolution, action or terms so made, taken or provided (including granting Special Approval) by the ACG Committee or our general partner with respect to such matter are conclusive and binding on all persons (including all of our partners) and do not constitute a breach of the partnership agreement, or any other agreement contemplated thereby, or a breach of any standard of care or duty imposed in the partnership agreement or under the Delaware Revised Uniform Limited Partnership Act or any other law, rule or regulation. The partnership agreement provides that it is presumed that the resolution, action or terms made, taken or provided by the ACG Committee or our general partner were not

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made, taken or provided in bad faith, and in any proceeding brought by any limited partner or by or on behalf of such limited partner or any other limited partner or us challenging such resolution, action or terms, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Director Independence

Messrs. McMahen, Smith and Andress 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.

The Parent Company (the registrant) has engaged Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, “Deloitte & Touche”) as its independent registered public accounting firm and principal accountants. The following table summarizes fees the Parent Company 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,
	2008		2007
Enterprise GP Holdings L.P.
Audit Fees (1)	$	545	$	959
Audit-Related Fees (2)		--		16
Tax Fees (3)		206		59
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 on Form 10-K. (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. In 2008, PricewaterhouseCoopers International Limited was engaged to perform the majority of our tax related services. (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 EPE Holdings has approved the use of Deloitte & Touche as the Parent Company’s 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 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

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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

For a listing of our consolidated financial statements and accompanying footnotes, see page F-1 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

The agreements included as exhibits are included only to provide information to investors regarding their terms. The agreements listed below may contain representations, warranties and other provisions that were made, among other things, to provide the parties thereto with specified rights and obligations and to allocate risk among them, and such agreements should not be relied upon as constituting or providing any factual disclosures about us, any other persons, any state of affairs or other matters.

Exhibit Number	Exhibit*
2.1	Securities Purchase Agreement, dated as of May 7, 2007, by and among Enterprise GP Holdings L.P., Natural Gas Partners VI, L.P., Ray C. Davis, Avatar Holdings, LLC, Avatar Investments, LP, Lon Kile, MHT Properties, Ltd., P. Brian Smith Holdings, LP., and LE GP, LLC (incorporated by reference to Exhibit 10.1 to Enterprise GP Holdings’ Form 8-K filed on May 10, 2007).
2.2	Securities Purchase Agreement, dated as of May 7, 2007, by and among Enterprise GP Holdings L.P., DFI GP Holdings L.P. and Duncan Family Interests, Inc. (incorporated by reference to Exhibit 10.4 to Enterprise GP Holdings’ Form 8-K filed on May 10, 2007).
3.1	First Amended and Restated Agreement of Limited Partnership of Enterprise GP Holdings L.P., dated as of August 29, 2005 (incorporated by reference to Exhibit 3.1 to Enterprise GP Holdings’ Form 10-Q filed November 4, 2005).
3.2	Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Enterprise GP Holdings L.P., dated as of May 7, 2007 (incorporated by reference to Exhibit 3.1 to Enterprise GP Holdings’ Form 8-K filed on May 10, 2007).
3.3	First Amendment to First Amended and Restated Partnership Agreement of Enterprise GP Holdings L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Enterprise GP Holdings’ Form 8-K/A filed on January 3, 2008).

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3.4	Second Amendment to First Amended and Restated Partnership Agreement of Enterprise GP Holdings L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to Form 8-K/A filed on January 3, 2008).
3.5	Third Amendment to First Amended and Restated Partnership Agreement of Enterprise GP Holdings L.P. dated as of November 6, 2008 (incorporated by reference to Exhibit 3.4 to Form 10-Q filed on November 10, 2008).
3.6	Third Amended and Restated Limited Liability Company Agreement of EPE Holdings, LLC, dated as of November 7, 2007 (incorporated by reference to Exhibit 3.3 to Form 10-Q filed on November 9, 2007).
3.7	First Amendment to Third Amended and Restated Limited Liability Company Agreement of EPE Holdings, LLC, dated as of November 6, 2008 (incorporated by reference to Exhibit 3.6 to Form 10-Q filed on November 10, 2008).
3.8	Certificate of Limited Partnership of Enterprise GP Holdings L.P. (incorporated by reference to Exhibit 3.1 to Amendment No. 2 to Enterprise GP Holdings’ Form S-1 Registration Statement, Reg. No. 333-124320, filed July 21, 2005).
3.9	Certificate of Formation of EPE Holdings, LLC (incorporated by reference to Exhibit 3.2 to Amendment No. 2 to Enterprise GP Holdings’ Form S-1 Registration Statement, Reg. No. 333-124320, filed July 21, 2005).
3.10	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 Enterprise Products Partners’ Form 8-K filed August 10, 2005).
3.11	First Amendment to the 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 Enterprise Products Partners’ Form 8-K filed January 3, 2008).
3.12	Second Amendment to the Fifth Amended and Restated Partnership Agreement of Enterprise Products Partners L.P. dated as of April 14, 2008 (incorporated by reference to Exhibit 10.1 to Enterprise Products Partners’ Form 8-K filed April 16, 2008).
3.13	Third Amendment to the Fifth Amended and Restated Partnership Agreement of Enterprise Products Partners L.P. dated as of November 6, 2008 (incorporated by reference to Exhibit 3.5 to Enterprise Products Partners’ Form 10-Q filed November 10, 2008).
3.14	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 Enterprise Products Partners’ Form 10-Q filed November 9, 2007).
3.15	First Amendment to Fifth Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, dated as of November 6, 2008 (incorporated by reference to Exhibit 3.7 to Enterprise Products Partners’ Form 8-K filed November 10, 2008).
3.16	Amended and Restated Limited Liability Company Agreement of Texas Eastern Products Pipeline Company, LLC dated May 7, 2007 (incorporated by reference to Exhibit 3 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (commission File No. 1-10403) filed on May 10, 2007).
3.17	First Amendment to Amended and Restated Limited Liability Company Agreement of Texas Eastern Products Pipeline Company, LLC dated November 6 2008 (incorporated by reference to Exhibit 3.6 to the Current Report on Form 10-Q of TEPPCO Partners, L.P. filed on November 7, 2008).
3.18	Fourth Amended and Restated Agreement of Limited Partnership of TEPPCO Partners, L.P., dated December 8, 2006 (Filed as Exhibit 3 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on December 13, 2006).
3.19	First Amendment to Fourth Amended and Restated Partnership Agreement of TEPPCO Partners, L.P. dated as of December 27, 2007 (incorporated by reference to Exhibit 3.1 to TEPPCO Partners’ Form 8-K filed December 28, 2007).
3.20	Second Amendment to Fourth Amended and Restated Partnership Agreement of TEPPCO Partners, L.P. dated as of November 6, 2008 (incorporated by reference to Exhibit 3.5 to the Form 10-Q filed by TEPPCO Partners, L.P. on November 7, 2008).
4.1	Specimen Unit certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 3 to Enterprise GP Holdings’ Form S-1 Registration Statement, Reg. No. 333-124320, filed August 11, 2005).

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4.2	Registration Rights Agreement dated as of July 17, 2007 by and among Enterprise GP Holdings L.P. and the Purchasers named therein (incorporated by reference to Exhibit 10.2 to Enterprise GP Holdings’ Form 8-K filed on July 12, 2007).
4.3	Second Amended and Restated Credit Agreement, dated as of May 1, 2007, by and among Enterprise GP Holdings L.P., as Borrower, the Lenders named therein, Citicorp North America, Inc., as Administrative Agent, Lehman Commercial Paper Inc., as Syndication Agent, Citibank, N.A., as Issuing Bank, and The Bank of Nova Scotia, Sun Trust Bank and Mizuho Corporate Bank, Ltd., as Co-Documentation Agent (incorporated by reference to Exhibit 10.5 to Enterprise GP Holdings’ Form 8-K filed May 10, 2007).
4.4	Third Amended and Restated Credit Agreement dated as of August 24, 2007, among Enterprise GP Holdings L.P., the Lenders party thereto, Citicorp North American, Inc., as Administrative Agent, and Citibank, N.A., as Issuing Bank. (incorporated by reference to Exhibit 4.1 to Form 8-K filed on August 30, 2007).
4.5	First Amendment to Third Amended and Restated Credit Agreement dated as of November 8, 2007, among Enterprise GP Holdings L.P., the Term Loan B Lenders party thereto, Citicorp North American, Inc., as Administrative Agent, and Citigroup Global Markets, Inc. and Lehman Brothers Inc. as Co-Arrangers and Joint Bookrunners (incorporated by reference to Exhibit 10.1 to Form 8-K filed on November 14, 2007).
4.6	Unit Purchase Agreement dated as of July 13, 2007 by and among Enterprise GP Holdings L.P., EPE Holdings, LLC and the Purchasers named therein (incorporated by reference to Exhibit 10.1 to Form 8-K filed on July 18, 2007).
4.7	Registration Rights Agreement dated as of July 17, 2007 by and among Enterprise GP Holdings L.P. and the Purchasers named therein (incorporated by reference to Exhibit 10.2 to Form 8-K filed on July 18, 2007).
4.8	Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Enterprise GP Holdings L.P., Natural Gas Partners VI, L.P. and Ray C. Davis (incorporated by reference to Exhibit 10.3 to Enterprise GP Holdings’ Form 8-K filed May 10, 2007).
10.1***	EPE Unit L.P. Agreement of Limited Partnership dated as of August 23, 2005 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on September 1, 2005).
10.2***	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).
10.3***	Second Amendment to Agreement of Limited Partnership of EPE Unit L.P. dated July 1, 2008 (incorporated by reference to Exhibit 10.1 to Enterprise GP Holdings’ Form 8-K filed July 7, 2008).
10.4***	EPE Unit II, L.P. Agreement of Limited Partnership dated as of December 5, 2006 (incorporated by reference to Exhibit 10.13 to Form 10-K filed by Enterprise Products Partners L.P. on February 28, 2007).
10.5***	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).
10.6***	Second Amendment to Agreement of Limited Partnership of EPE Unit II, L.P. dated July 1, 2008 (incorporated by reference to Exhibit 10.2 to Enterprise GP Holdings’ Form 8-K filed July 7, 2008).
10.7***	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 on May 10, 2007).
10.8***	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).
10.9***	Second Amendment to Agreement of Limited Partnership of EPE Unit III, L.P. dated July 1, 2008 (incorporated by reference to Exhibit 10.3 to Enterprise GP Holdings’ Form 8-K filed July 7, 2008).
10.10***	Agreement of Limited Partnership of TEPPCO Unit L.P. dated September 4, 2008 (incorporated by reference on to Exhibit 10.2 to the Form 8-K filed by TEPPCO Partners, L.P. on September 9, 2008).

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10.11***	Unit Purchase Agreement dated September 4, 2008 by and between TEPPCO Unit L.P. and TEPPCO Partners, L.P. (incorporated by reference on to Exhibit 10.1 to the Form 8-K filed by TEPPCO Partners, L.P. on September 9, 2008).
10.12***	EPCO Unit L.P. Agreement of Limited Partnership dated November 13, 2008 (incorporated by reference to Exhibit 10.5 to Form 10-K filed by Enterprise Products Partners L.P. on November 18, 2008).
10.13***	TEPPCO Unit II L.P. Agreement of Limited Partnership dated November 13, 2008 (incorporated by reference on to Exhibit 10.1 to the Form 8-K filed by TEPPCO Partners, L.P. on November 19, 2008).
10.14***	Enterprise Products Company 2005 EPE Long-Term Incentive Plan (amended and restated) (incorporated by reference to Exhibit 10.1 to Form 8-K filed on May 8, 2006).
10.15***	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 on August 11, 2005).
10.16***	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 on August 11, 2005).
10.17***	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 on May 8, 2006).
10.18***	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).
10.19***	Form of Option Grant Award under Enterprise Products 1998 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Form 10-Q filed on May 12, 2008).
10.20***	Amendment to Form of Option Grant Award under Enterprise Products 1998 Long-Term Incentive Plan for awards issued after April 10, 2007 but before May 7, 2008 (incorporated by reference to Exhibit 10.5 to Form 10-Q filed on May 12, 2008).
10.21***	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).
10.22***	Amended and Restated Enterprise Products 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-8 filed on May 6, 2008).
10.23***	Form of Restricted Unit Grant under the Amended and Restated Enterprise Products 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-8 filed on May 6, 2008).
10.24***	Form of Option Grant under the Amended and Restated Enterprise Products 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.3 to the Registration Statement on Form S-8 filed on May 6, 2008).
10.25***	EPCO, Inc. 2006 TPP Long-Term Incentive Plan (Filed as Exhibit B to the definitive proxy statement on Schedule 14A of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on September 11, 2006 and incorporated herein by reference).
10.26***	Form of TPP Employee Unit Appreciation Right Grant of Texas Eastern Products Pipeline Company, LLC under the EPCO, Inc. 2006 TPP Long-Term Incentive Plan (Filed as Exhibit 10.1 to the Current Report on Form 8-K of TEPPCO Partners, L.P. (Commission File No. 1-10403) filed on May 25, 2007 and incorporated herein by reference).
10.27***	Form of TPP Director Unit Appreciation Right Grant of Texas Eastern Products Pipeline Company, LLC under the EPCO, Inc. 2006 TPP Long-Term Incentive Plan (Filed as Exhibit 10.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2007 and incorporated herein by reference).
10.28***	Form of Phantom Unit Grant for Directors, as amended, of Texas Eastern Products Pipeline Company, LLC under the EPCO, Inc. TPP Long-Term Incentive Plan (Filed as Exhibit 10.3 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended June 30, 2007 and incorporated herein by reference).
10.29***	Form of TPP Employee Restricted Unit Grant, as amended, of Texas Eastern Products Pipeline Company, LLC under the EPCO, Inc. 2006 TPP Long-Term Incentive Plan (Filed as Exhibit 10.1 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended September 30, 2007 and incorporated herein by reference).

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10.30***	Form of TPP Employee Unit Option Grant under the EPCO, Inc. 2006 TPP Long-Term Incentive Plan (Filed as Exhibit 10.7 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2008 and incorporated herein by reference).
10.31***	Form of TPP Employee Amendment to Unit Option Grant under the EPCO, Inc. 2006 TPP Long-Term Incentive Plan for options granted between April 2007 and April 2008 (Filed as Exhibit 10.8 to Form 10-Q of TEPPCO Partners, L.P. (Commission File No. 1-10403) for the quarter ended March 31, 2008 and incorporated herein by reference).
10.32	Fifth Amended and Restated Administrative Services Agreement by and among EPCO, Inc., Enterprise Products Partners L.P., Enterprise Products Operating LLC, 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, LLC, TEPPCO Midstream Companies, LLC, TCTM, L.P. and TEPPCO GP, Inc. dated January 30, 2009 (incorporated by reference to Exhibit 10.1 to Form 8-K filed February 5, 2009 by Enterprise Products Partners).
10.33	Amended and Restated Limited Liability Company Agreement of LE GP, LLC, dated as of May 7, 2007 (incorporated by reference to Exhibit 10.2 to Enterprise GP Holdings’ Form 8-K filed May 10, 2007).
12.1#	Computation of ratio of earnings to fixed charges for each of the five years ended December 31, 2008, 2007, 2006, 2005 and 2004.
21.1#	List of subsidiaries as of February 25, 2009.
23.1#	Consent of Deloitte & Touche LLP.
23.2#	Consent of Grant Thornton LLP.
31.1#	Sarbanes-Oxley Section 302 certification of Dr. Ralph S. Cunningham for Enterprise GP Holdings L.P.’s annual report on Form 10-K for the year ended December 31, 2008.
31.2#	Sarbanes-Oxley Section 302 certification of W. Randall Fowler for Enterprise GP Holdings L.P.’s annual report on Form 10-K for the year ended December 31, 2008.
32.1#	Section 1350 certification of Dr. Ralph S. Cunningham for Enterprise GP Holdings L.P.’s annual report on Form 10-K for the year ended December 31, 2008.
32.2#	Section 1350 certification of W. Randall Fowler for Enterprise GP Holdings L.P.’s annual report on Form 10-K for the year ended December 31, 2008.
99.1#	Report of Independent Registered Public Accounting Firm – Grant Thornton LLP.

*	With respect to any exhibits incorporated by reference to any Exchange Act filings, the Commission files numbers for Enterprise Products Partners, Duncan Energy Partners and TEPPCO are 1-14323, 1-33266 and 1-10403, respectively.
***	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 Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 2, 2009.

ENTERPRISE GP HOLDINGS L.P.

(A Delaware Limited Partnership)

By: EPE Holdings, LLC, as general partner

By: /s/ Michael J. Knesek		Senior Vice President, Controller and Principal Accounting Officer
Michael J. Knesek		of the general partner

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 2, 2009.

Signature		Title (Position with EPE Holdings, LLC)
/s/ Dan L. Duncan		Director and Chairman
Dan L. Duncan
/s/ Dr. Ralph S. Cunningham		Director, President and Chief Executive Officer
Dr. Ralph S. Cunningham
/s/ Richard H. Bachmann		Director, Executive Vice President, Chief Legal Officer and Secretary
Richard H. Bachmann
/s/ W. Randall Fowler		Director, Executive Vice President and Chief Financial Officer
W. Randall Fowler
/s/ Randa Duncan Williams		Director
Randa Duncan Williams
/s/ O.S. Andras		Director
O.S. Andras
/s/ Charles E. McMahen		Director
Charles E. McMahen
/s/ Edwin E. Smith		Director
Edwin E. Smith
/s/ Thurmon Andress		Director
Thurmon Andress
/s/ Michael J. Knesek		Senior Vice President, Controller and Principal Accounting Officer
Michael J. Knesek

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Financial Statements and Supplementary Data.

ENTERPRISE GP HOLDINGS L.P.

INDEX TO FINANCIAL STATEMENTS

		Page No.
Report of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2008 and 2007		F-3

Statements of Consolidated Operations
	for the Years Ended December 31, 2008, 2007 and 2006	F-4

Statements of Consolidated Cash Flows
	for the Years Ended December 31, 2008, 2007 and 2006	F-5

Statements of Consolidated Partners’ Equity
	for the Years Ended December 31, 2008, 2007 and 2006	F-6

Notes to Consolidated Financial Statements
	Note 1 – Partnership Organization and Basis of Presentation	F-7
	Note 2 – Summary of Significant Accounting Policies	F-9
	Note 3 – Recent Accounting Developments	F-19
	Note 4 – Business Segments	F-21
	Note 5 – Revenue Recognition	F-24
	Note 6 – Accounting for Equity Awards	F-28
	Note 7 – Employee Benefit Plans	F-40
	Note 8 – Financial Instruments	F-42
	Note 9 – Cumulative Effect of Change in Accounting Principle	F-51
	Note 10 – Inventories	F-52
	Note 11 – Property, Plant and Equipment	F-53
	Note 12 – Investments in and Advances to Unconsolidated Affiliates	F-55
	Note 13 – Business Combinations	F-63
	Note 14 – Intangible Assets and Goodwill	F-67
	Note 15 – Debt Obligations	F-71
	Note 16 – Partners’ Equity and Distributions	F-84
	Note 17 – Related Party Transactions	F-87
	Note 18 – Provision for Income Taxes	F-93
	Note 19 – Earnings Per Unit	F-95
	Note 20 – Commitments and Contingencies	F-96
	Note 21 – Significant Risks and Uncertainties	F-103
	Note 22 – Supplemental Cash Flow Information	F-106
	Note 23 – Quarterly Financial Information (Unaudited)	F-108
	Note 24 – Supplemental Parent Company Financial Information	F-109

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of EPE Holdings, LLC and

Unitholders of Enterprise GP Holdings L.P.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Enterprise GP Holdings L.P. and subsidiaries (the "Company") as of December 31, 2008 and 2007, and the related consolidated statements of operations, cash flows, and partners’ equity for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Energy Transfer Equity L.P., an investment of the Company, which is accounted for by the use of the equity method. The Company’s equity in Energy Transfer Equity L.P.’s net income of $65.6 million (prior to the Company’s excess cost amortization – see Note 12) for the year ended December 31, 2008 is included in the accompanying consolidated financial statements. Energy Transfer Equity L.P.’s financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Energy Transfer Equity L.P., is based solely on the report of the other auditors.

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 and the report of the other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of the other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of Enterprise GP Holdings L.P. and subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, 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 effectiveness of the Company’s internal control over financial reporting as of December 31, 2008, 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 March 2, 2009 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 2, 2009

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ENTERPRISE GP HOLDINGS L.P.

CONSOLIDATED BALANCE SHEETS

(See Note 24 for Supplemental Parent Company Financial Information)

(Dollars in thousands)

	December 31,
ASSETS	2008			2007
Current assets:
Cash and cash equivalents	$	56,828		$	41,920
Restricted cash		203,789			53,144
Accounts and notes receivable – trade, net of allowance for doubtful accounts
of $17,682 at December 31, 2008 and $21,784 at December 31, 2007		2,028,458			3,363,295
Accounts receivable – related parties		182			1,995
Inventories		405,005			425,686
Derivative assets		218,537			12,741
Prepaid and other current assets		151,521			116,707
Total current assets		3,064,320			4,015,488
Property, plant and equipment, net		16,723,400			14,299,396
Investments in and advances to unconsolidated affiliates		2,510,702			2,539,003
Intangible assets, net of accumulated amortization of $674,861 at
December 31, 2008 and $545,645 at December 31, 2007		1,789,047			1,820,199
Goodwill		1,013,917			807,580
Deferred tax asset		355			3,545
Other assets, including restricted cash of $17,871 at December 31, 2007		269,605			238,891
Total assets	$	25,371,346		$	23,724,102

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable – trade	$	381,617		$	387,784
Accounts payable – related parties		17,543			14,192
Accrued product payables		1,845,568			3,571,095
Accrued expenses		65,683			61,981
Accrued interest		197,431			183,501
Derivative liabilities		316,164			98,646
Other current liabilities		292,224			292,304
Current maturities of long-term debt		--			353,976
Total current liabilities		3,116,230			4,963,479
Long-term debt (see Note 15)		12,714,928			9,507,229
Deferred tax liabilities		66,069			21,358
Other long-term liabilities		123,812			111,211
Commitments and contingencies
Minority interest		7,505,004			7,081,803
Partners’ equity:
Limited partners:
Units (123,191,640 registered Units outstanding at December 31, 2008 and 2007)		1,650,461			1,698,321
Class C Units (16,000,000 Class C Units outstanding at December 31, 2008 and 2007)		380,665			380,665
General partner		5			11
Accumulated other comprehensive loss		(185,828	)		(39,975	)
Total partners’ equity		1,845,303			2,039,022
Total liabilities and partners’ equity	$	25,371,346		$	23,724,102

See Notes to Consolidated Financial Statements

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ENTERPRISE GP HOLDINGS L.P.

STATEMENTS OF CONSOLIDATED OPERATIONS

(See Note 24 for Supplemental Parent Company Financial Information)

(Dollars in thousands, except per unit amounts)

	For Year Ended December 31,
	2008			2007			2006
Revenues:
Third parties	$	34,454,326		$	26,128,718		$	23,251,483
Related parties		1,015,250			585,051			360,663
Total revenue (see Note 4)		35,469,576			26,713,769			23,612,146
Cost and expenses:
Operating costs and expenses:
Third parties		32,868,672			24,937,723			21,976,271
Related parties		747,237			463,837			443,709
Total operating costs and expenses		33,615,909			25,401,560			22,419,980
General and administrative costs:
Third parties		50,018			49,520			36,894
Related parties		94,723			82,467			63,465
Total general and administrative costs		144,741			131,987			100,359
Total costs and expenses		33,760,650			25,533,547			22,520,339
Equity in earnings of unconsolidated affiliates		66,161			13,603			25,213
Operating income		1,775,087			1,193,825			1,117,020
Other income (expense):
Interest expense		(608,223	)		(487,419	)		(333,742	)
Interest income		7,485			11,382			9,820
Other, net (see Note 12 regarding gains in 2007)		2,183			60,406			1,360
Total other expense, net		(598,555	)		(415,631	)		(322,562	)
Income before taxes and minority interest		1,176,532			778,194			794,458
Provision for income taxes		(31,019	)		(15,813	)		(21,974	)
Income before minority interest		1,145,513			762,381			772,484
Minority interest		(981,458	)		(653,360	)		(638,585	)
Income before cumulative effect of change in accounting principle		164,055			109,021			133,899
Cumulative effect of change in accounting principle (see Note 9)		--			--			93
Net income	$	164,055		$	109,021		$	133,992

Net income allocation: (see Notes 16 and 19)
Limited partners’ interest in net income	$	164,039		$	109,010		$	133,979
General partner’s interest in net income	$	16		$	11		$	13

Earnings per unit: (see Note 19)
Basic and diluted income per Unit before change in accounting principle	$	1.33		$	0.97		$	1.30
Basic and diluted income per Unit	$	1.33		$	0.97		$	1.30

See Notes to Consolidated Financial Statements

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ENTERPRISE GP HOLDINGS L.P.

STATEMENTS OF CONSOLIDATED CASH FLOWS

(See Note 24 for Supplemental Parent Company Financial Information)

(Dollars in thousands)

	For Year Ended December 31,
	2008			2007			2006
Operating activities:
Net income	$	164,055		$	109,021		$	133,992
Adjustments to reconcile net income to net cash
flows provided by operating activities:
Depreciation, amortization and accretion in operating costs and expenses		725,048			647,652			556,553
Depreciation and amortization in general and administrative costs		14,476			13,664			7,329
Amortization in interest expense		223			1,094			(627	)
Equity in earnings of unconsolidated affiliates		(66,161	)		(13,603	)		(25,213	)
Distributions received from unconsolidated affiliates		157,211			116,930			76,515
Cumulative effect of change in accounting principle		--			--			(93	)
Operating lease expense paid by EPCO, Inc.		2,038			2,105			2,109
Minority interest		981,458			653,360			638,585
Gain from asset sales, ownership interests and related transactions		(3,971	)		(67,414	)		(9,112	)
Deferred income tax expense		6,235			7,626			15,078
Net effect of changes in operating accounts (see Note 22)		(414,624	)		457,598			44,276
Other (see Note 22)		556			8,801			182
Net cash flows provided by operating activities		1,566,544			1,936,834			1,439,574
Investing activities:
Capital expenditures		(2,539,426	)		(2,749,166	)		(1,724,827	)
Contributions in aid of construction costs		27,259			57,672			60,492
Proceeds from asset sales and related transactions		22,367			169,138			5,588
Increase in restricted cash		(132,775	)		(47,348	)		(8,715	)
Cash used for business combinations (see Note 13)		(553,486	)		(35,793	)		(292,202	)
Acquisition of intangible assets		(5,820	)		(14,516	)		--
Investments in unconsolidated affiliates		(62,208	)		(1,879,834	)		(25,881	)
Advances from (to) unconsolidated affiliates		(2,811	)		(41,251	)		14,898
Cash used in investing activities		(3,246,900	)		(4,541,098	)		(1,970,647	)
Financing activities:
Borrowings under debt agreements		13,255,504			11,416,785			4,343,410
Repayments of debt		(10,514,905	)		(8,652,028	)		(3,767,527	)
Debt issuance costs		(27,504	)		(39,192	)		(9,974	)
Net proceeds from the issuance of our Units, net		--			739,458			--
Distributions paid to minority interests (see Note 2)		(1,182,154	)		(1,073,938	)		(946,735	)
Distributions paid to partners		(213,119	)		(159,042	)		(108,449	)
Repurchase of option awards by subsidiary		--			(1,568	)		--
Acquisition of treasury units by subsidiary		(1,921	)		--			--
Contributions from minority interests		446,420			372,662			1,059,061
Cash distributions paid to former owners of TEPPCO interests		--			(29,760	)		(57,960	)
Settlement of cash flow hedging financial instruments		(66,542	)		49,103			--
Cash provided by financing activities		1,695,779			2,622,480			511,826
Effect of exchange rate changes on cash flows		(515	)		414			(232	)
Net change in cash and cash equivalents		15,423			18,216			(19,247	)
Cash and cash equivalents, January 1		41,920			23,290			42,769
Cash and cash equivalents, December 31	$	56,828		$	41,920		$	23,290

See Notes to Consolidated Financial Statements

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ENTERPRISE GP HOLDINGS L.P.

STATEMENTS OF CONSOLIDATED PARTNERS’ EQUITY

(See Note 16 for Unit History, Detail of Changes in Limited Partners’ Equity

and Accumulated Other Comprehensive Income (Loss))

(Dollars in thousands)

										Accumulated
										Other
	Limited			General			Comprehensive			Comprehensive
	Partners			Partner			Income			Income (Loss)			Total
Balance, December 31, 2005	$	1,450,511		$	12					$	19,083		$	1,469,606
Net income		133,979			13		$	133,992
Other comprehensive income: (see Note 8)
Cash flow hedges								3,821
Foreign current translation adjustment								(807	)
Proportionate share of other comprehensive income
of unconsolidated affiliates								--
Other comprehensive income								3,014			3,014
Comprehensive income							$	137,006						137,006
Cash distributions to partners		(108,438	)		(11	)					--			(108,449	)
Cash distributions to former owners of TEPPCO GP interests		(57,960	)		--						--			(57,960	)
Operating leases paid by EPCO, Inc.		109			--						--			109
Amortization of equity awards		80			--						--			80
Adoption of SFAS 158		--			--						(531	)		(531	)
Acquisition related disbursement of cash (see Note 16)		(319	)		--						--			(319	)
Change in accounting method for equity awards		(48	)		--						--			(48	)
Other		755			--						--			755
Balance, December 31, 2006		1,418,669			14						21,566			1,440,249
Net income		109,010			11		$	109,021
Other comprehensive loss: (see Note 8)
Cash flow hedges								(60,819	)
Change in funded status of Dixie benefit plans, net of tax								(52	)
Foreign currency translation adjustment								2,007
Proportionate share of other comprehensive loss of
unconsolidated affiliates								(3,848	)
Other comprehensive loss								(62,712	)		(62,712	)
Comprehensive income							$	46,309						46,309
Cash distributions to partners		(159,028	)		(14	)					--			(159,042	)
Cash distributions to former owners of TEPPCO GP interests		(29,760	)		--						--			(29,760	)
Operating leases paid by EPCO, Inc.		107			--						--			107
Net proceeds from the issuance of Units		739,458			--						--			739,458
Adoption of SFAS 158		--			--						1,171			1,171
Amortization of equity awards		530			--						--			530
Balance, December 31, 2007		2,078,986			11						(39,975	)		2,039,022
Net income		164,039			16		$	164,055
Other comprehensive loss: (see Note 8)
Cash flow hedges								(132,138	)
Change in funded status of Dixie benefit plans, net of tax								(1,339	)
Foreign currency translation adjustment								(2,501	)
Proportionate share of other comprehensive loss of
unconsolidated affiliates								(9,875	)
Other comprehensive loss								(145,853	)		(145,853	)
Comprehensive income							$	18,202						18,202
Cash distributions to partners		(213,097	)		(22	)								(213,119	)
Operating leases paid by EPCO, Inc.		103												103
Amortization of equity awards		1,133												1,133
Acquisition of treasury units by subsidiary,
net of minority interest amount of $1,873		(38	)											(38	)
Balance, December 31, 2008	$	2,031,126		$	5					$	(185,828	)	$	1,845,303

See Notes to Consolidated Financial Statements

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ENTERPRISE GP HOLDINGS 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 and Basis of Presentation

Partnership Organization

Enterprise GP Holdings L.P. is a publicly traded Delaware limited partnership, the limited partnership interests (the “Units”) of which are listed on the New York Stock Exchange (“NYSE”) under the ticker symbol “EPE.” The business of Enterprise GP Holdings L.P. is the ownership of general and limited partner interests of publicly traded partnerships engaged in the midstream energy industry and related businesses to increase cash distributions to its unitholders. Unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business of Enterprise GP Holdings L.P. and its consolidated subsidiaries.

References to “Enterprise Products Partners” mean Enterprise Products Partners L.P., the common units of which are listed on the NYSE under the ticker symbol “EPD.” Enterprise Products Partners has no business activities outside those conducted by its operating subsidiary, Enterprise Products Operating LLC (“EPO”). References to “EPGP” refer to Enterprise Products GP, LLC, which is the general partner of Enterprise Products Partners. EPGP is owned by the Parent Company.

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Basis of Presentation

General Purpose Consolidated and Parent Company-Only Information

In accordance with rules and regulations of the U.S. Securities and Exchange Commission (“SEC”) and various other accounting standard-setting organizations, our general purpose financial statements reflect the consolidation of the financial statements of businesses that we control through the ownership of general partner interests (e.g. Enterprise Products Partners and TEPPCO). Our general purpose consolidated financial statements present those investments in which we do not have a controlling interest as unconsolidated affiliates (e.g. Energy Transfer Equity and LE GP). To the extent that Enterprise Products Partners and TEPPCO reflect investments in unconsolidated affiliates in their respective consolidated financial statements, such investments will also be reflected as such in our general purpose financial statements unless subsequently consolidated by us due to common control considerations (e.g. Jonah Gas Gathering Company and Texas Offshore Port System). Also, minority interest presented in our financial statements reflects third-party and related party ownership of our consolidated subsidiaries, which include the third-party and related party unitholders of Enterprise Products Partners, TEPPCO and Duncan Energy Partners other than the Parent Company. Unless noted otherwise, the information presented in these financial statements reflects our consolidated businesses and operations.

In order for the unitholders of Enterprise GP Holdings L.P. and others to more fully understand the Parent Company’s business and financial statements on a standalone basis, Note 24 of these Notes to Consolidated Financial Statements includes information devoted exclusively to the Parent Company apart from that of our consolidated Partnership. A key difference between the non-consolidated Parent Company financial information and those of our consolidated Partnership is that the Parent Company views each of its investments (e.g. Enterprise Products Partners, TEPPCO and Energy Transfer Equity) as unconsolidated affiliates and records its share of the net income of each as equity earnings in the Parent Company income information. In accordance with U.S. generally accepted accounting principles (“GAAP”), we eliminate such equity earnings in the preparation of our consolidated Partnership financial statements.

Presentation of Investments

At December 31, 2008, the Parent Company owned 13,670,925 common units of Enterprise Products Partners and 100% of the membership interests of EPGP, which is entitled to 2.0% of the cash distributions paid by Enterprise Products Partners as well as the associated incentive distribution rights (“IDRs”) of Enterprise Products Partners.

Private company affiliates of EPCO (DFI and DFIGP) contributed equity interests in TEPPCO and TEPPCO GP to the Parent Company in May 2007. As a result of such contributions, the Parent Company owns 4,400,000 common units of TEPPCO and 100.0% of the membership interests of TEPPCO GP, which is entitled to 2.0% of the cash distributions of TEPPCO as well as the IDRs of TEPPCO. The contributions of ownership interests in TEPPCO and TEPPCO GP were accounted for at historical costs as a reorganization of entities under common control in a manner similar to a pooling of interests. The inclusion of TEPPCO and TEPPCO GP in our financial statements was effective January 1, 2005 because

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an affiliate of EPCO under common control with the Parent Company originally acquired the ownership interests of TEPPCO GP in February 2005.

Our Consolidated Financial Statements and Parent Company financial information reflect investments in TEPPCO and TEPPCO GP as follows:

§	Ownership of 100.0% of the membership interests in TEPPCO GP and associated TEPPCO IDRs for all periods presented. See Note 24 for additional information regarding TEPPCO IDRs.

§	Ownership of 4,400,000 common units of TEPPCO since the date of issuance to affiliates of EPCO in December 2006.

All earnings derived from TEPPCO IDRs and TEPPCO common units in excess of those allocated to the Parent Company are presented as a component of minority interest in our Consolidated Financial Statements. In addition, the former owners of the TEPPCO and TEPPCO GP interests and rights were allocated all cash receipts from these investments during the periods they owned such interests prior to May 2007. This method of presentation is intended to show how the contributed interests would have affected our business.

In May 2007, the Parent Company acquired 38,976,090 common units of Energy Transfer Equity and approximately 34.9% of the membership interests of its general partner, LE GP, for $1.65 billion in cash. Energy Transfer Equity owns limited partner interests and the general partner interest of ETP. We account for our investments in Energy Transfer Equity and LE GP using the equity method of accounting. See Note 12 for additional information regarding these unconsolidated affiliates.

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 periods indicated:

	For Year Ended December 31,
	2008			2007			2006
Balance at beginning of period	$	21,784		$	23,506		$	37,579
Charges to expense		3,532			2,639			537
Deductions		(7,634	)		(4,361	)		(14,610	)
Balance at end of period	$	17,682		$	21,784		$	23,506

See “Credit Risk Due to Industry Concentrations” in Note 21 for more information.

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.

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Our Statements of Consolidated Cash Flows are prepared using the indirect method. The indirect method derives net cash flows provided by 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) other non-cash amounts such as depreciation, amortization, changes in the fair market value of financial instruments and equity in earnings of unconsolidated affiliates and (iv) the effects of all items classified as investing or financing cash flows, such as proceeds from asset sales and related transactions or extinguishment of debt.

The former owners of the TEPPCO and TEPPCO GP interests and rights were allocated all cash receipts from these investments during the periods they owned such interests prior to May 2007.

Consolidation Policy

Our financial statements include our accounts and those of our majority-owned subsidiaries in which we have a controlling financial or equity interest, after the elimination of intercompany accounts and transactions. We evaluate our financial interests in companies 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.

If an investee 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 3.0% and 50.0% and we exercise significant influence over the investee’s operating and financial policies. For all other types of investments, we apply the equity method of accounting if our ownership interest is between 20.0% and 50.0% and we exercise significant influence over the investee’s operating and financial policies. In consolidation, we eliminate our proportionate share of profits and losses from transactions with equity method unconsolidated affiliates to the extent such amounts are material and remain on our balance sheet (or those of our equity method investees) in inventory or similar accounts.

If our ownership interest in an investee does not provide us with either control or significant influence over the investee, we account for the investment using the cost method. We currently have no investments accounted for using the cost method.

See “Basis of Presentation” under Note 1 for information regarding our consolidation of Enterprise Products Partners, TEPPCO and their respective general partners.

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 assessments inherently involve 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.

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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 5.0% of total current assets and liabilities, respectively.

Deferred Revenues

Amounts billed in advance of the period in which the service is rendered or product delivered are recorded as deferred revenue. At December 31, 2008 and 2007, deferred revenues totaled $118.5 million and $87.4 million, respectively, and were recorded as a component of other current and long-term liabilities, as appropriate, on our Consolidated Balance Sheets. See Note 5 for information regarding our revenue recognition policies.

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

Statement of Financial Accounting Standards (“SFAS”) 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of SFAS 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 (loss).

Our consolidated results reflect immaterial amounts related to active and terminated employee benefit plans. See Note 7 for additional information regarding our current employee benefit plans.

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. Expenditures to mitigate or prevent future environmental contamination are capitalized. 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. At December 31, 2008 and 2007, none of our estimated environmental remediation liabilities are discounted to present value since the ultimate amount and timing of cash payments for such liabilities are not readily determinable.

At December 31, 2008 and 2007, our accrued liabilities for environmental remediation projects totaled $22.3 million and $30.5 million, respectively. These amounts were derived from a range of reasonable estimates based upon studies and site surveys. Unanticipated changes in circumstances and/or legal requirements could result in expenses being incurred in future periods in addition to an increase in actual cash required to remediate contamination for which we are responsible. The majority of these amounts relate to reserves established by Enterprise Products Partners for remediation activities involving mercury gas meters.

In February 2007, Enterprise Products Partners reserved $6.5 million in cash it received from a third party to fund anticipated 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

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indemnify Enterprise Products Partners 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 periods indicated:

	For Year Ended December 31,
	2008			2007			2006
Balance at beginning of period	$	30,461		$	25,980		$	24,537
Charges to expense		5,886			3,777			2,992
Acquisition-related additions and other		--			6,499			8,811
Deductions and other		(14,049	)		(5,795	)		(10,360	)
Balance at end of period	$	22,298		$	30,461		$	25,980

Equity Awards

See Note 6 for additional information regarding our equity awards.

Estimates

Preparing our financial statements in conformity with GAAP requires management to make estimates and assumptions that affect amounts presented in the financial statements (i.e. assets, liabilities, revenue and expenses) and disclosures about contingent assets and liabilities. 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.

Enterprise Products Partners revised the remaining useful lives of certain assets, most notably the assets that constitute its Texas Intrastate System, effective January 1, 2008. This revision adjusted the remaining useful life of such assets to incorporate recent data showing that proved natural gas reserves supporting throughput and processing volumes for these assets have changed since our original determination made in September 2004. These revisions will prospectively reduce our depreciation expense on assets having carrying values totaling $2.72 billion at January 1, 2008. For additional information regarding this change in estimate, see Note 11.

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 at market-based prices and included in accounts receivable, and net exchange volumes loaned to us under such agreements are valued at market-based prices and accrued as a liability in accrued product payables.

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

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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, forwards and other contracts to manage price risks associated with inventories, firm commitments, interest rates, foreign currency and certain anticipated transactions. We recognize these transactions as assets or liabilities on our Consolidated Balance Sheets based on the instrument’s 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.

Changes in fair value of financial instrument contracts are recognized in earnings in the current period (i.e., using mark-to-market accounting) 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 (loss), which is generally referred to as “AOCI.” Gains and losses on cash flow hedges are reclassified from accumulated other comprehensive income (loss) to earnings when the forecasted transaction occurs or, as appropriate, over the economic life of the hedged item. A contract designated as a hedge of an anticipated transaction that is no longer likely to occur is immediately recognized in earnings.

To qualify for hedge accounting, 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 8 for additional information regarding our financial instruments.

Foreign Currency Translation

Enterprise Products Partners owns an 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 loss 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. See Note 8 for information regarding our hedging of currency risk.

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 14 for additional information regarding our goodwill.

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Impairment Testing for Intangible Assets with Indefinite Lives

Intangible assets with indefinite lives are subject to periodic testing for recoverability in a manner similar to goodwill. We test the carrying value of indefinite-lived intangible assets for impairment annually, or more frequently if circumstances indicate that it is more likely than not that the fair value of the asset is less than its carrying value. This test is performed during the fourth quarter of each fiscal year. If the estimated fair value of this intangible asset is less than its carrying value, a charge to earnings is required to reduce the asset’s carrying value to its implied fair value.

At December 31, 2008 and 2007, the Parent Company had an indefinite-life intangible asset valued at $606.9 million associated with IDRs in TEPPCO’s quarterly cash distributions. Our estimate of the fair value of this asset is based on a number of assumptions including: (i) the discount rate we select to present value underlying cash flow streams; (ii) the expected increase in TEPPCO’s cash distribution rate over a discreet forecast period; and (iii) the long-term growth rate of TEPPCO’s cash distributions beyond the discreet forecast period. The financial models we use to estimate the fair value of the IDRs are sensitive to changes in these assumptions. Consequently, a significant change in any of these underlying assumptions may result in our recording an impairment charge where none was warranted in prior periods.

We did not record any intangible asset impairment charges for any of the periods presented.

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 such asset impairment charges were recorded in 2008 or 2007.

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 investee or long-term negative changes in the investee’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 (“Nemo”) for impairment. As a result of this evaluation, we recorded a $7.0 million non-cash impairment charge that is a component of “Equity in earnings of unconsolidated affiliates” on our Statements of Consolidated Operations 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 in earnings of unconsolidated affiliates” on our Statements of Consolidated Operations for the year ended December 31, 2006. We had no such impairment charges during the year ended

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December 31, 2008. See Note 12 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 and certain federal and state tax obligations of Seminole Pipeline Company (“Seminole”) and Dixie Pipeline Company (“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.

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, which applied to corporations and limited liability companies, to include limited partnerships and limited liability partnerships. As a result of the change in tax law, our tax status in the State of Texas 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 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 50.0% 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, petroleum products, 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 10 for additional information regarding our inventories.

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Minority Interest

As presented in our Consolidated Balance Sheets, minority interest represents third-party and affiliate ownership interests in the net assets of our consolidated subsidiaries. For financial reporting purposes, the assets and liabilities of our controlled subsidiaries are consolidated with those of the Parent Company, with any third-party and affiliate ownership in such amounts presented as minority interest. The following table presents the components of minority interest as presented on our Consolidated Balance Sheets at the dates indicated:

	December 31,
	2008			2007
Limited partners of Enterprise Products Partners:
Third-party owners of Enterprise Products Partners (1)	$	5,010,595		$	5,011,700
Related party owners of Enterprise Products Partners (2)		347,720			278,970
Limited partners of Duncan Energy Partners:
Third-party owners of Duncan Energy Partners (1)		281,071			288,588
Limited partners of TEPPCO:
Third-party owners of TEPPCO (1,3)		1,733,518			1,372,821
Related party owners of TEPPCO (2)		(16,048	)		(12,106	)
Joint venture partners (4)		148,148			141,830
Total minority interest on consolidated balance sheets	$	7,505,004		$	7,081,803

(1) Consists of non-affiliate public unitholders of Enterprise Products Partners, Duncan Energy Partners and TEPPCO. (2) Consists of unitholders of Enterprise Products Partners and TEPPCO that are related party affiliates of the Parent Company. This group is primarily comprised of EPCO and certain of its private company consolidated subsidiaries. (3) The increase in minority interest during 2008 is primarily due to TEPPCO’s issuance of common units in a public offering in September 2008. TEPPCO sold 9.2 million of its common units at a price of $29.00 per unit, which generated net proceeds of $257.0 million. In addition, minority interest increased due to TEPPCO’s issuance of common units in connection with its marine services acquisition during the first quarter of 2008. See Note 13 for additional information regarding this business acquisition. (4) Represents third-party ownership interests in joint ventures that we consolidate, including Seminole, Tri-States Pipeline L.L.C. (“Tri-States”), Independence Hub LLC (“Independence Hub”), Wilprise Pipeline Company LLC (“Wilprise”) and the Texas Offshore Port System (see Note 4).

Minority interest expense amounts attributable to the limited partners of Enterprise Products Partners, Duncan Energy Partners and TEPPCO primarily represent allocations of earnings by these entities to their unitholders, excluding those earnings allocated to the Parent Company in connection with its ownership of common units of Enterprise Products Partners and TEPPCO. The following table presents the components of minority interest as presented on our Statements of Consolidated Operations for the periods indicated:

	For Year Ended December 31,
	2008		2007		2006
Limited partners of Enterprise Products Partners (1)	$	786,528	$	404,779	$	486,398
Limited partners of Duncan Energy Partners (2)		17,300		13,879		--
Related party former owners of TEPPCO GP		--		--		16,502
Limited partners of TEPPCO (3)		153,592		217,938		126,606
Joint venture partners (4)		24,038		16,764		9,079
Total	$	981,458	$	653,360	$	638,585

(1) Minority interest expense attributable to this subsidiary increased in 2008 relative to 2007 primarily due to an increase in Enterprise Products Partners’ operating income, partially offset by an increase in interest expense. In addition, the number of Enterprise Products Partners’ common units outstanding increased in 2008 relative to 2007. (2) Duncan Energy Partners completed its initial public offering in February 2007. The increase in minority interest expense during 2008 is primarily due to an increase in Duncan Energy Partners’ net income. (3) Minority interest expense attributable to this subsidiary decreased in 2008 relative to 2007 primarily due to a decrease in TEPPCO’s net income in 2008. TEPPCO recognized an approximate $60.0 million gain on the sale of an equity investment in the first quarter of 2007. (4) Represents third-party ownership interests in joint ventures we consolidate.

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The following table presents distributions paid to and contributions received from minority interests as presented on our Statements of Consolidated Cash Flows for the periods indicated:

	For Year Ended December 31,
	2008		2007		2006
Distributions paid to minority interests:
Limited partners of Enterprise Products Partners	$	865,728	$	807,515	$	717,300
Limited partners of Duncan Energy Partners		24,817		15,757		--
Related party former owners of TEPPCO GP		--		--		23,939
Limited partners of TEPPCO		260,575		234,097		196,665
Joint venture partners		31,034		16,569		8,831
Total distributions paid to minority interests	$	1,182,154	$	1,073,938	$	946,735
Contributions from minority interests:
Limited partners of Enterprise Products Partners	$	134,928	$	67,994	$	836,425
Limited partners of Duncan Energy Partners		--		290,466		--
Limited partners of TEPPCO		275,857		1,697		195,058
Joint venture partners		35,635		12,505		27,578
Total contributions received from minority interests	$	446,420	$	372,662	$	1,059,061

Distributions paid to the limited partners of Enterprise Products Partners, Duncan Energy Partners and TEPPCO primarily represent the quarterly cash distributions paid by these entities to their unitholders, excluding those paid to the Parent Company in connection with its ownership of common units of Enterprise Products Partners and TEPPCO.

Contributions from the limited partners of Enterprise Products Partners, Duncan Energy Partners and TEPPCO primarily represent proceeds each entity received from common unit offerings and distribution reinvestment plans, excluding those received from the Parent Company. Contributions from the limited partners of Duncan Energy Partners represent the net proceeds received by Duncan Energy Partners in connection with its initial public offering in February 2007. Contributions from the limited partners of TEPPCO increased during 2008 relative to 2007 primarily due to the net proceeds TEPPCO received from its common unit offering in September 2008.

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 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.

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At December 31, 2008 and 2007, our natural gas imbalance receivables, net of allowance for doubtful accounts, were $63.4 million and $73.9 million, respectively, and are reflected as a component of “Accounts and notes receivable – trade” on our Consolidated Balance Sheets. At December 31, 2008 and 2007, our imbalance payables were $50.8 million and $48.7 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.

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. Under our depreciation policy for midstream energy assets, the remaining economic lives of such assets are limited to the estimated life of the natural resource basins (based on proved reserves at the time of the analysis) from which such assets derive their throughput or processing volumes. Our forecast of the remaining life for the applicable resource basins is based on several factors, including information published by the U.S. Energy Information Administration. Where appropriate, we use other depreciation methods (generally accelerated) for tax purposes.

Leasehold improvements are recorded as a component of property, plant and equipment. The cost of leasehold improvements is charged to earnings using the straight-line method over the shorter of the remaining lease term or the estimated useful lives of the improvements. We consider renewal terms that are deemed reasonably assured when estimating remaining lease terms.

Our assumptions regarding the useful economic lives and residual values of our assets may change in response to new facts and circumstances, which would change our depreciation amounts prospectively. Examples of such circumstances include, but are not limited to, the following: (i) changes in laws and regulations that limit the estimated economic life of an asset; (ii) changes in technology that render an asset obsolete; (iii) changes in expected salvage values; or (iv) significant changes in the forecast life of proved reserves of applicable resource basins, if any. See Note 11 for additional information regarding our property, plant and equipment, including a change in depreciation expense beginning January 1, 2008 resulting from a change in the estimated useful life of certain assets.

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; however, the cost of annual planned major maintenance projects are deferred and recognized ratably over the remaining portion of the calendar year in which such projects occur.

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. We will incur a gain or loss to the extent that our ARO liabilities are not settled at their recorded amounts. See Note 11 for additional information regarding our AROs.

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Restricted Cash

Restricted cash represents amounts held in connection with Enterprise Products Partners’ commodity financial instruments portfolio and New York Mercantile Exchange (“NYMEX”) physical natural gas purchases. Additional cash may be restricted to maintain our positions as commodity prices fluctuate or deposit requirements change. At December 31, 2007, restricted cash also included amounts held by a third party trustee responsible for disbursing proceeds from Enterprise Products Partners’ Petal GO Zone bond offering. During 2008, virtually all proceeds from the Petal GO Zone bonds were released by the trustee to fund construction costs associated with the expansion of Enterprise Products Partners’ Petal, Mississippi storage facility. The following table presents the components of our restricted cash balances at the periods indicated:

	December 31,
	2008		2007
Amounts held in brokerage accounts related to
commodity hedging activities and physical natural gas purchases	$	203,789	$	53,144
Proceeds from Petal GO Zone bonds reserved for construction costs		1		17,871
Total restricted cash	$	203,790	$	71,015

Revenue Recognition

See Note 5 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.

Note 3. Recent Accounting Developments

The accounting standard setting bodies have recently issued the following accounting guidance that will affect our future financial statements: SFAS 141(R), Business Combinations; FASB Staff Position (“FSP”) SFAS 142-3, Determination of the Useful Life of Intangible Assets; SFAS 157, Fair Value Measurements; SFAS 160, Noncontrolling Interests in Consolidated Financial Statements – An amendment of ARB 51; SFAS 161, Disclosures about Derivative Instruments and Hedging Activities – An Amendment of SFAS 133; and Emerging Issues Task Force (“EITF”) 08-6, Equity Method Investment Accounting Considerations.

SFAS 141(R), Business Combinations. SFAS 141(R) replaces SFAS 141, Business Combinations and was effective January 1, 2009. SFAS 141(R) retains the fundamental requirements of SFAS 141 in that the acquisition method of accounting (previously termed the “purchase method”) be used for all business combinations and for the “acquirer” to be identified in 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. SFAS 141(R) will have an impact on the way in which we evaluate acquisitions.

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:

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§	Recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interests in the acquiree.

Recognizes and measures any goodwill acquired in the business combination or a gain resulting 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 net income 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.

FSP FAS 142-3, Determination of the Useful Life of Intangible Assets. FSP 142-3 revised the factors that should be considered in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets under SFAS 142, Goodwill and Other Intangible Assets. These revisions are intended to improve consistency between the useful life of a recognized intangible asset under SFAS 142 and the period of expected cash flows used to measure the fair value of such assets under SFAS 141(R) and other accounting guidance. The measurement and disclosure requirements of this new guidance will be applied to intangible assets acquired after January 1, 2009. Our adoption of this guidance is not expected to have a material impact on our consolidated financial statements.

SFAS 157, Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Although certain provisions of SFAS 157 were effective January 1, 2008, the remaining guidance of this new standard applicable to nonfinancial assets and liabilities was effective January 1, 2009. See Note 8 for information regarding fair value-related disclosures required for 2008 in connection with SFAS 157.

SFAS 157 applies 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 are 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. Our adoption of this guidance is not expected to have a material impact on our consolidated financial statements. SFAS 157 will impact the valuation of assets and liabilities (and related disclosures) in connection with future business combinations and impairment testing.

SFAS 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment of ARB 51. SFAS 160 established accounting and reporting standards for noncontrolling interests, which have been referred to as minority interests in prior accounting literature. SFAS 160 was effective January 1, 2009. A noncontrolling interest is that portion of equity in a consolidated subsidiary not attributable, directly or indirectly, to a reporting entity. 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” presentation); (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 reporting entity and noncontrolling interests on the face of the statement of income; and (iii) enhanced disclosures regarding noncontrolling interests.

SFAS 160 will affect the presentation of minority interest on our financial statements beginning with the first quarter of 2009. Minority interest in the nets assets of our consolidated subsidiaries will be presented as a component of partners’ equity on our Consolidated Balance Sheets. With respect to our Statements of Consolidated Operations, net income and comprehensive income will be allocated between minority interests and us, as applicable.

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SFAS 161, Disclosures about Derivative Instruments and Hedging Activities - An Amendment of SFAS 133. SFAS 161 revised the disclosure requirements for financial instruments and related hedging activities to provide users of financial statements with an enhanced understanding of (i) why and how an entity uses financial instruments, (ii) how an entity accounts for financial instruments and related hedged items under SFAS 133, Accounting for Derivative Instruments and Hedging Activities (including related interpretations), and (iii) how financial instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows.

SFAS 161 requires qualitative disclosures about objectives and strategies for using financial instruments, quantitative disclosures about fair value amounts of and gains and losses on financial instruments, and disclosures about credit risk-related contingent features in financial instrument agreements. SFAS 161 was effective January 1, 2009 and we will apply its requirements beginning with the first quarter of 2009.

EITF 08-6, Equity Method Investment Accounting Considerations. EITF 08-6 clarifies the accounting for certain transactions and impairment considerations involving equity method investments under SFAS 141(R) and SFAS 160. EITF 08-6 generally requires that (i) transaction costs should be included in the initial carrying value of an equity method investment; (ii) an equity method investor shall not test separately an investee’s underlying assets for impairment, rather such testing should be performed in accordance with Opinion 18 (i.e., on the equity method investment itself); (iii) an equity method investor shall account for a share issuance by an investee as if the investor had sold a proportionate share of its investment (any gain or loss to the investor resulting from the investee’s share issuance shall be recognized in earnings); and (iv) a gain or loss should not be recognized when changing the method of accounting for an investment from the equity method to the cost method. EITF 08-6 was effective January 1, 2009.

Note 4. Business Segments

§	Investment in Enterprise Products Partners – Reflects the consolidated operations of Enterprise Products Partners and its general partner, EPGP. This segment also includes the development stage assets of the Texas Offshore Port System (as defined below).

The joint venture’s primary project, referred to as “TOPS,” includes (i) an offshore port (which will be located approximately 36 miles from Freeport, Texas), (ii) an onshore storage facility with approximately 3.9 million barrels of crude oil storage capacity, and (iii) an 85-mile crude oil pipeline system having a transportation capacity of up to 1.8 million barrels per day, that will extend from the offshore port to a storage facility near Texas City, Texas. The joint venture’s complementary project, referred to as the Port Arthur Crude Oil Express (or “PACE”) will transport crude oil from Texas City, including crude oil from TOPS, and will consist of a 75-mile pipeline and 1.2 million barrels of crude oil storage capacity in the Port Arthur, Texas area. Development of the TOPS and PACE projects is supported by long-term contracts with affiliates of Motiva Enterprises LLC (“Motiva”) and Exxon Mobil Corporation (“Exxon Mobil”), which have committed a combined 725,000 barrels per day of crude oil to the projects. The timing of

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construction and related capital costs of the TOPS and PACE projects will be affected by the expansion plans of Motiva and the acquisition of requisite permits.

§	Investment in TEPPCO – Reflects the consolidated operations of TEPPCO and its general partner, TEPPCO GP. This segment also includes the assets and operations of Jonah Gas Gathering Company (“Jonah”).

§	Investment in Energy Transfer Equity – Reflects the Parent Company’s investments in Energy Transfer Equity and its general partner, LE GP. These investments were acquired in May 2007. The Parent Company accounts for these non-controlling investments using the equity method of accounting.

Each of the respective general partners of Enterprise Products Partners, TEPPCO and Energy Transfer Equity have separate operating management and boards of directors, with at least three independent directors. We control Enterprise Products Partners and TEPPCO through our ownership of their respective general partners. We do not control Energy Transfer Equity or its general partner.

Segment revenues and expenses include intersegment transactions, which are generally based on transactions made at market-related rates. Our consolidated totals reflect the elimination of intersegment transactions.

We classify equity in earnings of unconsolidated affiliates as a component of operating income. Our equity method investments in Energy Transfer Equity and LE GP are an integral component of our primary business strategy to increase cash distributions to unitholders. Also, the equity method investments of our consolidated subsidiaries (i.e., Enterprise Products Partners and TEPPCO) represent an integral component of their respective business strategies. Such investments are a means by which Enterprise Products Partners and TEPPCO align their commercial interests with those of customers and/or suppliers who are joint owners in such entities. This method of operation enables Enterprise Products Partners and TEPPCO to achieve favorable economies of scale relative to the level of investment and business risk assumed versus what they could accomplish on a stand-alone basis. Given the interrelated

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nature of such entities to the operations of Enterprise Products Partners and TEPPCO, we believe the presentation of equity earnings from such unconsolidated affiliates as a component of operating income is meaningful and appropriate.

Financial information presented for our Investment in Enterprise Products Partners and Investment in TEPPCO business segments was derived from the underlying consolidated financial statements of EPGP and TEPPCO GP, respectively. Financial information presented for our Investment in Energy Transfer Equity segment represents amounts we record in connection with these equity method investments based on publicly available information of Energy Transfer Equity.

The following table presents selected business segment information for the periods indicated:

	Investment					Investment
	in					in
	Enterprise		Investment			Energy		Adjustments
	Products		in			Transfer		and			Consolidated
	Partners		TEPPCO			Equity		Eliminations			Totals
Revenues from external customers:
Year ended December 31, 2008	$	20,769,206	$	13,685,120		$	--	$	--		$	34,454,326
Year ended December 31, 2007		16,297,409		9,831,309			--		--			26,128,718
Year ended December 31, 2006		13,587,739		9,663,744			--		--			23,251,483
Revenues from related parties: (1)
Year ended December 31, 2008		1,136,450		80,785			--		(201,985	)		1,015,250
Year ended December 31, 2007		652,716		31,367			--		(99,032	)		585,051
Year ended December 31, 2006		403,230		27,576			--		(70,143	)		360,663
Total revenues: (1)
Year ended December 31, 2008		21,905,656		13,765,905			--		(201,985	)		35,469,576
Year ended December 31, 2007		16,950,125		9,862,676			--		(99,032	)		26,713,769
Year ended December 31, 2006		13,990,969		9,691,320			--		(70,143	)		23,612,146
Equity in earnings of unconsolidated affiliates:
Year ended December 31, 2008		37,734		(2,871	)		31,298		--			66,161
Year ended December 31, 2007		20,301		(9,793	)		3,095		--			13,603
Year ended December 31, 2006		21,327		3,886			--		--			25,213
Operating income: (2)
Year ended December 31, 2008		1,391,516		364,455			31,298		(12,182	)		1,775,087
Year ended December 31, 2007		873,248		332,273			3,095		(14,791	)		1,193,825
Year ended December 31, 2006		857,541		270,053			--		(10,574	)		1,117,020
Segment assets: (3)
At December 31, 2008		17,775,434		6,083,352			1,598,876		(86,316	)		25,371,346
At December 31, 2007		16,372,652		5,801,710			1,653,463		(103,723	)		23,724,102
Investments in and advances
to unconsolidated affiliates (see Note 12):
At December 31, 2008		655,573		256,478			1,598,876		(225	)		2,510,702
At December 31, 2007		622,502		263,038			1,653,463		--			2,539,003
Intangible Assets (see Note 14): (4)
At December 31, 2008		855,416		950,931			--		(17,300	)		1,789,047
At December 31, 2007		917,000		920,780			--		(17,581	)		1,820,199
Goodwill (see Note 14):
At December 31, 2008		706,884		307,033			--		--			1,013,917
At December 31, 2007		591,651		215,929			--		--			807,580
(1) Amounts presented in the “Adjustments and Eliminations” column represent the elimination of intercompany revenues. (2) Amounts presented in the “Adjustments and Eliminations” column represent the elimination of intercompany revenues and expenses. (3) Amounts presented in the “Adjustments and Eliminations” column represent the elimination of intercompany receivables and investment balances, as well as the elimination of contracts Enterprise Products Partners purchased in cash from TEPPCO in 2006. (4) Amounts presented in the “Adjustments and Eliminations” column represent the elimination of contracts Enterprise Products Partners purchased from TEPPCO in 2006.

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The following tables present total segment revenues by business line for each of Enterprise Products Partners and TEPPCO for the periods indicated. Enterprise Products Partners operates in four primary business lines: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Offshore Pipelines & Services; and (iv) Petrochemical Services. At December 31, 2007, TEPPCO operated in three business lines: (i) Downstream, (ii) Upstream and (iii) Midstream. Effective February 1, 2008, TEPPCO added a fourth business line, Marine Services, with the acquisition of its marine services business (see Note 13).

Enterprise Products Partners

	Business Line
			Onshore
	NGL		Natural Gas		Offshore
	Pipelines		Pipelines		Pipelines		Petrochemical					Segment
	& Services		& Services		& Services		Services		Eliminations			Totals
Year ended December 31, 2008	$	23,329,840	$	4,406,029	$	269,828	$	3,322,339	$	(9,422,380	)	$	21,905,656
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

Sales of tangible products, primarily NGLs, natural gas and petrochemicals, by Enterprise Products Partners aggregated $20.38 billion, $15.37 billion and $12.43 billion for the years ended December 31, 2008, 2007 and 2006, respectively.

TEPPCO

	Business Line
							Marine					Segment
	Downstream		Upstream		Midstream		Services		Eliminations			Totals
Year ended December 31, 2008	$	372,964	$	12,873,426	$	355,242	$	164,274	$	(192	)	$	13,765,714
Year ended December 31, 2007		362,691		9,173,683		326,381		--		(549	)		9,862,206
Year ended December 31, 2006		304,301		9,109,629		361,399		--		(7,714	)		9,767,615

Sales of petroleum products, primarily crude oil, by TEPPCO were $12.84 billion, $9.15 billion and $9.08 billion for the years ended December 31, 2008, 2007 and 2006, respectively.

Note 5. 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) collectibility is reasonably assured. The following information provides a general description of the underlying revenue recognition policies of Enterprise Products Partners and TEPPCO.

Enterprise Products Partners

Enterprise Products Partners operates in four primary business lines: (i) NGL Pipelines & Services; (ii) Onshore Natural Gas Pipelines & Services; (iii) Offshore Pipelines & Services; and (iv) Petrochemical Services.

NGL Pipelines & Services. This aspect of Enterprise Products Partners’ 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 Enterprise Products Partners’ natural gas processing activities, it enters 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, Enterprise Products Partners takes ownership of mixed NGLs extracted from the producer’s natural gas stream and recognize revenue when

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the extracted NGLs are delivered and sold to customers under NGL marketing sales contracts. In the same way, revenue is recognized under Enterprise Products Partners’ percent-of-liquids contracts except that the volume of NGLs it extracts and sells 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 Enterprise Products Partners extracts. Under a percent-of-proceeds contract, Enterprise Products Partners shares in the proceeds generated from the sale of the mixed NGLs it extracts on the producer’s behalf. If a cash fee for natural gas processing services is stipulated by the contract, Enterprise Products Partners records revenue when the natural gas has been processed and delivered to the producer.

Enterprise Products Partners’ NGL marketing activities generate revenues from the sale of NGLs obtained from either its 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 Enterprise Products Partners’ 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”).

Enterprise Products Partners collects storage revenues under its 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, Enterprise Products Partners collects a fee for reserving storage capacity for customers in its 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 Enterprise Products Partners’ 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 Enterprise Products Partners’ 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.

Enterprise Products Partners enters into fee-based arrangements and percent-of-liquids contracts for the NGL fractionation services it provides 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 Enterprise Products Partners’ NGL fractionation facilities generate revenues using percent-of-liquids contracts. Such contracts allow Enterprise Products Partners 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 Enterprise Products Partners sells and delivers the retained NGLs to customers.

Onshore Natural Gas Pipelines & Services. This aspect of Enterprise Products Partners’ 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 Enterprise Products Partners’ 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

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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.

Enterprise Products Partners’ 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 Enterprise Products Partners’ business generates revenues from the provision of offshore natural gas and crude oil pipeline transportation services and related offshore platform operations. Enterprise Products Partners’ 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 million British thermal units) 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 Enterprise Products Partners’ revenues from its offshore crude oil pipelines are generated based upon a transportation fee per unit of volume (typically in barrels) multiplied by the volume delivered to the customer. A substantial portion of these revenues are attributable to long-term transportation agreements with producers. The revenues Enterprise Products Partners earns for its services are dependent on the volume of crude oil to be delivered and the level of fees charged to customers.

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 Enterprise Products Partners’ 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 million cubic feet 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. Enterprise Products Partners’ Independence Hub and Marco Polo offshore platforms earn a significant amount of demand revenues. The Independence Hub platform will earn $54.6 million of demand revenues annually through March 2012. The Marco Polo platform will earn $2.1 million of demand revenues monthly through March 2009.

Petrochemical Services. This aspect of Enterprise Products Partners’ business generates revenues from the provision of isomerization and propylene fractionation services and the sale of certain petrochemical products. Enterprise Products Partners’ 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.

Enterprise Products Partners’ 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.

TEPPCO

At December 31, 2008, TEPPCO operated in four business lines: (i) Downstream, (ii) Upstream, (iii) Midstream and (iv) Marine Services.

Downstream. This aspect of TEPPCO’s business generates revenues primarily from the provision of pipeline transportation (LPGs and refined products), product storage, terminalling and marketing

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services. Under TEPPCO’s LPG and refined products pipeline transportation tariffs, revenue is recognized when volumes have been delivered to customers. Revenue from these tariffs is generally based upon a fixed fee per barrel 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 FERC.

TEPPCO collects storage revenues under its refined products and LPG 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. Revenues from product terminalling activities are recorded in the period such services are provided. Customers are typically billed a fee per unit of volume loaded.

TEPPCO’s refined products marketing activities generate revenues from the sale of refined products acquired from third parties. Revenues from these sales contracts are recognized when the refined products are delivered to customers. In general, the sales prices referenced in these contracts are market-related.

Upstream. This aspect of TEPPCO’s business generates revenues primarily from the provision of crude oil gathering, transportation, marketing and storage services and the distribution of lubrication oils and specialty chemical products. TEPPCO generates crude oil gathering, transportation and storage revenues from contractual agreements and tariffs. Revenue from crude oil gathering and transportation tariffs is generally based upon a fixed fee per barrel transported multiplied by the volume delivered. Crude oil storage revenues are recognized ratably over the length of the storage period based on the storage fees specified in each contract. Certain of TEPPCO’s crude oil pipeline transportation rates are regulated by the FERC.

TEPPCO’s crude oil marketing activities generate revenues from the sale of crude oil acquired from third parties. Revenue from these sales contracts is recognized when the crude is delivered to customers. In general, the sales prices referenced in these contracts are market-related.

Midstream. This aspect of TEPPCO’s business generates revenues primarily from the provision of natural gas gathering and NGL transportation and fractionation services. TEPPCO’s natural gas gathering systems generate revenues from gathering agreements where shippers are billed a fee per unit of volume gathered (typically in MMBtus or Mcf) multiplied by the volume gathered. The gathering fees charged under these arrangements are contractual. Revenues associated with these fee-based contracts are recognized when volumes are received by the customer.

Under TEPPCO’s 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 barrel 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 FERC.

TEPPCO provides NGL fractionation services under a fee-based arrangement. Under the fee-based arrangement, revenue is recognized based upon the volume of NGLs fractionated at a fixed rate per gallon.

Marine Services. This aspect of TEPPCO’s business generates revenues primarily from the provision of inland and offshore transportation of refined products, crude oil, condensate, asphalt, heavy fuel oil and other heated oil products via boats and tank barges. Under TEPPCO’s marine services transportation contracts, revenue is recognized over the transit time of individual tows as determined on an individual contract basis, which is generally less than ten days in duration. Revenue from these contracts is generally based on set day rates or a set fee per cargo movement.

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Note 6. Accounting for Equity Awards

We account for equity awards in accordance with SFAS 123(R), Share-Based Payment. SFAS 123(R) requires us to recognize compensation expense related to equity 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 equity awards is estimated using the Black-Scholes option pricing model. 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-classified awards are settled in cash 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, of which $1.4 million was allocated to minority interest in the Partnership’s consolidated financial statements, 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 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.

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The following tables summarize our equity compensation amounts by plan during each of the periods indicated:

	For Year Ended December 31,
	2008			2007		2006
Parent Company:
EPGP UARs	$	(10	)	$	97	$	23
EPCO Employee Partnerships		335			104		26
EPCO 1998 Long-term Incentive Plan (“1998 Plan”)		437			165		149
Total Parent Company		762			366		198
Enterprise Products Partners:
EPCO Employee Partnerships		5,535			3,911		2,146
Enterprise Products Partners 2008 Long-Term Incentive Plan (“2008 EPD LTIP”)		87			--		--
EPCO 1998 Plan (1)		9,255			12,168		5,720
DEP GP UARs		1			69		--
Total Enterprise Products Partners		14,878			16,148		7,866
TEPPCO:
EPCO Employee Partnerships (2)		793			426		--
EPCO 1998 Plan (2)		1,038			636		201
TEPPCO 1994 Long-Term Incentive Plan		--			--		4
TEPPCO 1999 Phantom Unit Retention Plan (“1999 Plan”)		(128	)		865		885
TEPPCO 2000 Long-Term Incentive Plan (“2000 LTIP”)		(265	)		397		352
TEPPCO 2005 Phantom Unit Plan (“2005 Phantom Unit Plan”)		(144	)		976		1,152
EPCO 2006 TPP Long-Term Incentive Plan (“2006 LTIP”)		1,187			482		--
Total TEPPCO		2,481			3,782		2,594
Total compensation expense	$	18,121		$	20,296	$	10,658

(1) Amounts presented for the year ended December 31, 2007 include $4.6 million associated with the resignation of a former chief executive officer of Enterprise Products Partners’ general partner. (2) Represents amounts allocated to TEPPCO in connection with the use of shared services under an Administrative Services Agreement (“ASA”) with EPCO.

EPGP UARs

The non-employee directors of EPGP 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, the Parent Company or Enterprise Products Partners. These 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 the Parent Company’s Units (determined as of a future vesting date) over the grant date fair value. These UARs are accounted for similar to liability awards under SFAS 123(R) since they will be settled with cash.

At December 31, 2008 and 2007, we had a total of 90,000 outstanding UARs granted to non-employee directors of EPGP that cliff vest in 2011. If a director resigns prior to vesting, his UAR awards are forfeited. The grant date fair value with respect to 10,000 of the UARs is based on a Unit price of $35.71. The grant date fair value with respect to the remaining 80,000 UARS is based on a Unit price of $34.10.

EPCO Employee Partnerships

As long-term incentive arrangements, EPCO has granted its key employees who perform services on behalf of us, EPCO and other affiliated companies, “profits interests” in seven limited partnerships (the “Employee Partnerships”), which are private company affiliates of EPCO. The employees were issued Class B limited partner interests and admitted as Class B limited partners in the Employee Partnerships without capital contributions. As discussed and defined above, the Employee Partnerships are: EPE Unit I; EPE Unit II; EPE Unit III; Enterprise Unit; EPCO Unit; TEPPCO Unit and TEPPCO Unit II. Enterprise Unit, EPCO Unit, TEPPCO Unit and TEPPCO Unit II were formed in 2008.

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The Class B limited partner interests entitle each holder to participate in the appreciation in value of the publicly traded limited partner units owned by the underlying Employee Partnership. With the exception of TEPPCO Unit and TEPPCO Unit II, the Employee Partnerships own either Enterprise GP Holdings units (“EPE units”) or Enterprise Products Partners’ common units (“EPD units”) or both. TEPPCO Unit and TEPPCO Unit II own common units of TEPPCO (“TPP 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 and upon certain change of control events.

We account for the profits interest awards under SFAS 123(R). As a result, the compensation expense attributable to these awards is based on the estimated grant date fair value of each award. An allocated portion of the fair value of these equity-based awards is charged to us under the ASA (see Note 17). We are not responsible for reimbursing EPCO for any expenses of the Employee Partnerships, including the value of any contributions of cash or limited partner units made by private company affiliates of EPCO at the formation of each Employee Partnership. However, pursuant to the ASA, beginning in February 2009 we will reimburse EPCO for our allocated share of distributions of cash or securities made to the Class B limited partners of EPCO Unit and TEPPCO Unit II.

Each Employee Partnership has a single Class A limited partner, which is a privately-held indirect subsidiary of EPCO, and a varying number of Class B limited partners. At formation, the Class A limited partner either contributes cash or limited partner units it owns to the Employee Partnership. If cash is contributed, the Employee Partnership uses these funds to acquire limited partner units on the open market. In general, the Class A limited partner earns a preferred return (either fixed or variable depending on the partnership agreement) on its investment (“Capital Base”) in the Employee Partnership and any residual quarterly cash amounts, if any, are distributed to the Class B limited partners. Upon liquidation, Employee Partnership assets having a fair market value equal to the Class A limited partner’s Capital Base, plus any preferred return for the period in which liquidation occurs, will be distributed to the Class A limited partner. Any remaining assets will be distributed to the Class B limited partner(s) as a residual profits interest.

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The following table summarizes key elements of each Employee Partnership as of December 31, 2008:

		Initial	Class A
		Class A	Partner	Award	Grant Date	Unrecognized
Employee	Description	Capital	Preferred	Vesting	Fair Value	Compensation
Partnership	of Assets	Base	Return	Date (1)	of Awards (2)	Cost (3)

EPE Unit I	1,821,428 EPE units	$51.0 million	4.50% to 5.725% (4)	November 2012	$17.0 million	$9.3 million

EPE Unit II	40,725 EPE units	$1.5 million	4.50% to 5.725% (4)	February 2014	$0.3 million	$0.2 million

EPE Unit III	4,421,326 EPE units	$170.0 million	3.80%	May 2014	$32.7 million	$25.1 million

Enterprise Unit	881,836 EPE units 844,552 EPD units	$51.5 million	5.00%	February 2014	$4.2 million	$3.7 million

EPCO Unit	779,102 EPD units	$17.0 million	4.87%	November 2013	$7.2 million	$7.0 million

TEPPCO Unit	241,380 TPP units	$7.0 million	4.50% to 5.725%	September 2013	$2.1 million	$1.7 million

TEPPCO Unit II	123,185 TPP units	$3.1 million	6.31%	November 2013	$1.4 million	$1.4 million

(1) The vesting date may be accelerated for change of control and other events as described in the underlying partnership agreements. (2) Our estimated grant date fair values were determined using a Black-Scholes option pricing model and reflect adjustments for forfeitures, regrants and other modifications. See following table for information regarding our fair value assumptions. (3) Unrecognized compensation cost represents the total future expense to be recognized by the EPCO group of companies as of December 31, 2008. We will recognize our allocated share of such costs in the future. The period over which the unrecognized compensation cost will be recognized is as follows for each Employee Partnership: 3.9 years, EPE Unit I; 5.1 years, EPE Unit II; 5.4 years, EPE Unit III; 5.1 years, Enterprise Unit; 4.9 years, EPCO Unit; 4.7 years, TEPPCO Unit; and 4.9 years, TEPPCO Unit II. (4) In July 2008, the Class A preferred return was reduced from 6.25% to the floating amounts presented.

The following table summarizes the assumptions we used in deriving the estimated grant date fair value for each of the Employee Partnerships using a Black-Scholes option pricing model:

	Expected	Risk-Free	Expected		Expected
Employee	Life	Interest	Distribution Yield		Unit Price Volatility
Partnership	of Award	Rate	EPE/EPD units	TPP units	EPE/EPD units	TPP units

EPE Unit I	3 to 5 years	2.7% to 5.0%	3.0% to 4.8%	n/a	16.6% to 30.0%	n/a
EPE Unit II	5 to 6 years	3.3% to 4.4%	3.8% to 4.8%	n/a	18.7% to 19.4%	n/a
EPE Unit III	4 to 6 years	3.2% to 4.9%	4.0% to 4.8%	n/a	16.6% to 19.4%	n/a
Enterprise Unit	6 years	2.7% to 3.9%	4.5% to 8.0%	n/a	15.3% to 22.1%	n/a
EPCO Unit	5 years	2.4%	11.1%	n/a	50.0%	n/a
TEPPCO Unit	5 years	2.9%	n/a	7.3%	n/a	16.4%
TEPPCO Unit II	5 years	2.4%	n/a	13.9%	n/a	66.4%

EPCO 1998 Plan

The EPCO 1998 Plan provides for the issuance of up to 7,000,000 common units of Enterprise Products Partners. After giving effect to outstanding option awards at December 31, 2008 and the issuance and forfeiture of restricted unit awards through December 31, 2008, a total of 814,764 additional common units of Enterprise Products Partners could be issued under the EPCO 1998 Plan.

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Enterprise Products Partners’ unit option awards. Under the EPCO 1998 Plan, non-qualified incentive options to purchase a fixed number of Enterprise Products Partners’ common units may be granted to key employees of EPCO who perform management, administrative or operational functions for Enterprise Products Partners. When issued, the exercise price of each option grant is equivalent to the market price of the underlying equity on the date of grant. During 2008, in response to changes in the federal tax code applicable to certain types of equity awards, Enterprise Products Partners amended the terms of certain of its outstanding unit options. In general, the expiration dates of these awards were modified from May and August 2017 to December 2012.

In order to fund its obligations under the EPCO 1998 Plan, EPCO may purchase common units at fair value either in the open market or directly from Enterprise Products Partners. When EPCO employees exercise their options, Enterprise Products Partners reimburses EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the common units issued to the employee.

The fair value of each 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 Enterprise Products Partners’ common units, and expected unit price volatility of Enterprise Products Partners’ common units. In general, the expected life of an option represents the period of time that the option is expected to be outstanding based on an analysis of historical option activity. Enterprise Products Partners’ selection of a 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 assumptions are based on several factors, which include an analysis of Enterprise Products Partners’ historical unit price volatility and distribution yield over a period equal to the expected life of the option.

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The following table presents option activity under the EPCO 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, 2005		2,082,000		$	22.16
Granted (2)		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 (3)		895,000			30.63
Exercised		(256,000	)		19.26
Settled or forfeited (4)		(740,000	)		24.62
Outstanding at December 31, 2007 (5)		2,315,000			26.18
Exercised		(61,500	)		20.38
Forfeited		(85,000	)		26.72
Outstanding at December 31, 2008		2,168,500			26.32		5.19	$	--
Options exercisable at:
December 31, 2006		591,000		$	20.85		5.11	$	4,808
December 31, 2007		335,000		$	22.06		3.96	$	3,291
December 31, 2008 (6)		548,500		$	21.47		4.08	$	--

(1) Aggregate intrinsic value reflects fully vested unit options at the date indicated. (2) The total grant date fair value of these awards was $1.2 million based on the following assumptions: (i) expected life of options of seven years; (ii) risk-free interest rate of 5.0%; (iii) expected distribution yield on Enterprise Products Partners’ common units of 8.9%; and (iv) expected unit price volatility on Enterprise Products Partners’ common units of 23.5%. (3) 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 Enterprise Products Partners’ common units of 8.4%; and (iv) weighted-average expected unit price volatility on Enterprise Products Partners’ common units of 23.2%. (4) Includes the settlement of 710,000 options in connection with the resignation of the former chief executive officer of Enterprise Products Partners’ general partner. (5) During 2008, Enterprise Products Partners amended the terms of certain of its outstanding unit options. In general, the expiration dates of these awards were modified from May and August 2017 to December 2012. (6) Enterprise Products Partners was committed to issue 2,168,500 and 2,315,000 of its common units at December 31, 2008 and 2007, respectively, if all outstanding options awarded under the EPCO 1998 Plan (as of these dates) were exercised. An additional 365,000, 480,000, and 775,000 of these options are exercisable in 2009, 2010 and 2012, respectively.

The total intrinsic value of option awards exercised during the years ended December 31, 2008, 2007 and 2006 were $0.6 million, $3.0 million and $2.2 million, respectively. During the years ended December 31, 2008, 2007 and 2006, we recognized $0.4 million, $4.4 million and $0.7 million, respectively, of compensation expense in connection with unit option awards under the EPCO 1998 Plan.

At December 31, 2008, there was an estimated $1.7 million of total unrecognized compensation cost related to nonvested unit options granted under the EPCO 1998 Plan. We expect to recognize our share of this cost over a weighted-average period of 2.1 years in accordance with the ASA. At December 31, 2007, there was an estimated $2.8 million of total unrecognized compensation cost related to nonvested options granted under the EPCO 1998 Plan.

During the years ended December 31, 2008, 2007 and 2006, Enterprise Products Partners received cash of $0.7 million, $7.5 million and $5.6 million, respectively, from the exercise of unit options. Conversely, its option-related reimbursements to EPCO were $0.6 million, $3.0 million and $1.8 million, respectively.

Enterprise Products Partners’ restricted unit awards. Under the EPCO 1998 Plan, Enterprise Products Partners may also issue restricted common units to key employees of EPCO and directors of EPGP. In general, the restricted unit awards allow recipients to acquire the underlying common units at no

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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 Enterprise Products Partners to its unitholders. Since restricted units are issued securities of Enterprise Products Partners, such distributions are reflected as a component of cash distributions to minority interests as shown on our Statements of Consolidated Cash Flows. Enterprise Products Partners paid $3.9 million, $2.6 million and $1.6 million in cash distributions with respect to restricted units during the years ended December 31, 2008, 2007 and 2006, respectively.

The following table summarizes information regarding Enterprise Products Partners’ restricted unit awards for the periods indicated:

				Weighted-
				average grant
	Number of			date fair value
	units			per unit (1)
Restricted units at December 31, 2005		751,604
Granted (2)		466,400		$	25.21
Vested		(42,136	)	$	24.02
Forfeited		(70,631	)	$	22.86
Restricted units at December 31, 2006		1,105,237
Granted (3)		738,040		$	25.61
Vested		(4,884	)	$	25.28
Forfeited		(36,800	)	$	23.51
Settled (4)		(113,053	)	$	23.24
Restricted units at December 31, 2007		1,688,540
Granted (5)		766,200		$	24.93
Vested		(285,363	)	$	23.11
Forfeited		(88,777	)	$	26.98
Restricted units at December 31, 2008		2,080,600

(1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The weighted-average grant date fair value per unit for forfeited and vested awards is determined before an allowance for forfeitures. (2) Aggregate grant date fair value of restricted unit awards issued during 2006 was $10.8 million based on grant date market prices of Enterprise Products Partners’ common units ranging from $24.85 to $27.45 per unit and estimated forfeiture rates ranging from 7.8% to 9.8%. (3) Aggregate grant date fair value of restricted unit awards issued during 2007 was $18.9 million based on grant date market prices of Enterprise Products Partners’ common units ranging from $28.00 to $31.83 per unit and estimated forfeiture rates ranging from 4.6% to 17.0%. (4) Reflects the settlement of restricted units in connection with the resignation of the former chief executive officer Enterprise Products Partners’ general partner. (5) Aggregate grant date fair value of restricted unit awards issued during 2008 was $19.1 million based on grant date market prices of Enterprise Products Partners’ common units ranging from $25.00 to $32.31 per unit and estimated forfeiture rate of 17.0%.

The total fair value of restricted unit awards that vested during the years ended December 31, 2008, 2007 and 2006 was $6.6 million, $0.1 million and $1.1 million, respectively. During the years ended December 31, 2008, 2007 and 2006, we recognized $8.8 million, $7.7 million and $5.0 million, respectively, of compensation expense in connection with restricted unit awards under the EPCO 1998 Plan.

At December 31, 2008, there was an estimated $31.5 million of total unrecognized compensation cost related to restricted common units of Enterprise Products Partners granted under the EPCO 1998 Plan. We expect to recognize our share of this cost over a weighted-average period of 2.3 years in accordance

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with the ASA. At December 31, 2007, there was an estimated $25.5 million of total unrecognized compensation cost related to restricted unit awards granted under the EPCO 1998 Plan.

Enterprise Products Partners’ 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 Enterprise Products Partners’ 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 Enterprise Product Partners to its unitholders.

EPD 2008 LTIP

On January 29, 2008, the unitholders of Enterprise Products Partners approved the EPD 2008 LTIP, which provides for awards of Enterprise Products Partners’ common units and other rights to its non-employee directors and to consultants and employees of EPCO and its affiliates providing services to Enterprise Products Partners. Awards under the EPD 2008 LTIP may be granted in the form of unit options, restricted units, phantom units, UARs and DERs. The EPD 2008 LTIP is administered by EPGP’s Audit, Conflicts and Governance (“ACG”) Committee. The EPD 2008 LTIP provides for the issuance of up to 10,000,000 of Enterprise Products Partners’ common units. After giving effect to option awards outstanding at December 31, 2008, a total of 9,205,000 additional common units of Enterprise Products Partners could be issued under the EPD 2008 LTIP.

The EPD 2008 LTIP may be amended or terminated at any time by the Board of Directors of EPCO or EPGP’s ACG Committee; however, the rules of the NYSE require that any material amendment, such as a significant increase in the number of common units available under the plan or a change in the types of awards available under the plan, would require the approval of Enterprise Products Partners’ unitholders. 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 EPD 2008 LTIP is effective until the earlier of January 29, 2018 or 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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Enterprise Products Partners’ unit option awards. The exercise price of Enterprise Products Partners’ unit options awarded to participants is determined by EPGP’s ACG Committee (at its discretion) at the date of grant and may be no less than the fair market value of Enterprise Products Partners’ common units at the date of grant. The following table presents unit option activity under the EPD 2008 LTIP for the periods indicated:

Weighted-

Average

Remaining

Number of

Strike Price

Contractual

Units

(dollars/unit)

Term (in years)

Outstanding at January 1, 2008

Granted (1)

795,000

30.93

Outstanding at December 31, 2008 (2)

795,000

30.93

5.00

(1) Aggregate grant date fair value of these unit options issued during 2008 was $1.6 million based on the following assumptions: (i) a grant date market price of Enterprise Products Partners’ common units of $30.93 per unit; (ii) expected life of options of 4.7 years; (iii) risk-free interest rate of 3.3%; (iv) expected distribution yield on Enterprise Products Partners’ common units of 7.0%; (v) expected unit price volatility on Enterprise Products Partners’ common units of 19.8%; and (vi) an estimated forfeiture rate of 17.0%.

(2) The 795,000 units outstanding at December 31, 2008 will become exercisable in 2013.

At December 31, 2008, there was an estimated $1.3 million of total unrecognized compensation cost related to nonvested unit options granted under the EPD 2008 LTIP. Enterprise Products Partners expects to recognize its share of this cost over a remaining period of 3.4 years in accordance with the ASA.

Enterprise Products Partners’ phantom unit awards. The EPD 2008 LTIP also provides for the issuance of phantom unit awards of Enterprise Products Partners. 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 Enterprise Products Partners’ common units on the redemption date. Each participant is required to redeem their phantom units as they vest, which typically is three years from the date the award is granted. There were a total of 4,400 phantom units granted under the 2008 LTIP during the fourth quarter of 2008 and outstanding at December 31, 2008. These awards cliff vest in 2011. At December 31, 2008, Enterprise Products Partners had an accrued liability of $5 thousand for compensation related to these phantom unit awards.

DEP GP UARs

The non-employee directors of DEP GP, the general partner of Duncan Energy Partners, 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, the Parent Company, Duncan Energy Partners or Enterprise Products Partners. The compensation expense associated with these awards is recognized by DEP GP, which is our consolidated subsidiary. These 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 the Parent Company’s Units (determined as of a future vesting date) over the grant date fair value. These UARs are accounted for similar to liability awards under SFAS 123(R) since they will be settled with cash.

As of December 31, 2008 and 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 a Unit price of $36.68 per unit.

TEPPCO 1999 Plan

The TEPPCO 1999 Plan provides for the issuance of phantom unit awards as incentives to key employees of EPCO working on behalf of TEPPCO. These liability awards are settled for cash based on the fair market value of the vested portion of the phantom units at redemption dates in each award. The fair market value of each phantom unit award is equal to the closing price of TEPPCO’s common units on the

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NYSE on the redemption date. Each participant is required to redeem their phantom units as they vest. In addition, each participant is entitled to cash distributions equal to the product of the number of phantom unit awards granted under the TEPPCO 1999 Plan and the cash distribution per unit paid by TEPPCO on its common units. Grants under the 1999 Plan are subject to forfeiture if the participant’s employment with EPCO is terminated.

A total of 18,600 and 31,600 phantom units were outstanding under the TEPPCO 1999 Plan at December 31, 2008 and 2007, respectively. In April 2008, 13,000 phantom units vested and $0.4 million was paid out to a participant in the second quarter of 2008. The awards outstanding at December 31, 2008 cliff vest as follows: 13,000 in April 2009 and 5,600 in January 2010. At December 31, 2008 and 2007, TEPPCO had accrued liability balances of $0.4 million and $1.0 million, respectively, related to the TEPPCO 1999 Plan. For the years ended December 31, 2008 and 2007, phantom unitholders under the TEPPCO 1999 Plan received $62 thousand and $95 thousand in cash distributions, respectively. Since phantom units do not represent issued securities of TEPPCO, the cash payments with respect to these phantom units are expensed by TEPPCO as paid.

TEPPCO 2000 LTIP

The TEPPCO 2000 LTIP provides key employees of EPCO working on behalf of TEPPCO incentives to achieve improvements in TEPPCO’s financial performance. Generally, upon the close of a three-year performance period, each recipient will receive a cash payment equal to (i) the applicable “performance percentage” (as defined in the award agreement) multiplied by (ii) the number of phantom units granted under the TEPPCO 2000 LTIP multiplied by (iii) the average of the closing prices of TEPPCO common units over the ten consecutive days immediately preceding the last day of the specified performance period. In addition, during the performance period, each participant is entitled to cash distributions equal to the product of the number of phantom units granted under the TEPPCO 2000 LTIP and the cash distribution per unit paid by TEPPCO on its common units. Grants under the TEPPCO 2000 LTIP are accounted for as liability awards and subject to forfeiture if the recipient’s employment with EPCO is terminated, with customary exceptions for death, disability or retirement.

A participant’s “performance percentage” is based upon an improvement in Economic Value Added for TEPPCO during a given three-year performance period over the Economic Value Added for the three-year period immediately preceding the performance period. The term “Economic Value Added” means TEPPCO’s average annual EBITDA for the performance period minus the product of TEPPCO’s average asset base and its cost of capital for the performance period. In this context, EBITDA means TEPPCO’s earnings before net interest expense, other income, depreciation and amortization and TEPPCO’s proportional interest in the EBITDA of its joint ventures, except that its chief executive officer of TEPPCO may exclude gains or losses from extraordinary, unusual or non-recurring items. Average asset base means the quarterly average, during the performance period, of TEPPCO’s gross carrying value of property, plant and equipment, plus long-term inventory, and the gross carrying value of intangible assets and equity investments. TEPPCO’s cost of capital is determined at the date each award is granted.

At December 31, 2008, a total of 11,300 phantom units were outstanding under the TEPPCO 2000 LTIP that cliff vested on December 31, 2008 and will be paid out to participants in the first quarter of 2009. On December 31, 2007, 19,700 phantom units were outstanding under the TEPPCO 2000 LTIP. On December 31, 2007, 8,400 phantom units vested and $0.5 million was paid out to participants in the first quarter of 2008. At December 31, 2008 and 2007, TEPPCO had accrued liability balances of $0.2 million and $0.9 million, respectively, related to the TEPPCO 2000 LTIP. After payout in the first quarter of 2009 on awards which vested on December 31, 2008, there will be no remaining phantom units outstanding under the TEPPCO 2000 LTIP. For the years ended December 31, 2008 and 2007, phantom unitholders under the TEPPCO 2000 LTIP received $38 thousand and $54 thousand in cash distributions, respectively.

TEPPCO 2005 Phantom Unit Plan

The TEPPCO 2005 Phantom Unit Plan provides key employees of EPCO working on behalf of TEPPCO incentives to achieve improvements in TEPPCO’s financial performance. Generally, upon the

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close of a three-year performance period, the recipient will receive a cash payment equal to (i) the recipient’s vested percentage (as defined in the award agreement) multiplied by (ii) the number of phantom units granted under the TEPPCO 2005 Phantom Unit Plan multiplied by (iii) the average of the closing prices of TEPPCO common units over the ten consecutive days immediately preceding the last day of the specified performance period. In addition, during the performance period, each recipient is entitled to cash distributions equal to the product of the number of phantom units granted under the TEPPCO 2005 Phantom Unit Plan and the cash distribution per unit paid by TEPPCO on its common units. Grants under the TEPPCO 2005 Phantom Unit Plan are accounted for as liability awards and subject to forfeiture if the recipient’s employment with EPCO is terminated, with customary exceptions for death, disability or retirement.

Generally, a participant’s vested percentage is based upon an improvement in TEPPCO’s EBITDA during a given three-year performance period over EBITDA for the three-year period preceding the performance period. In this context, EBITDA means TEPPCO’s earnings before minority interest, net interest expense, other income, income taxes, depreciation and amortization and TEPPCO’s proportional interest in the EBITDA of its joint ventures, except that its chief executive officer of TEPPCO may exclude gains or losses from extraordinary, unusual or non-recurring items.

At December 31, 2008 a total of 36,600 phantom units were outstanding under the TEPPCO 2005 Phantom Unit Plan that cliff vested on December 31, 2008 and will be paid out to participants in the first quarter of 2009. On December 31, 2007, 74,400 phantom units were outstanding under the TEPPCO 2005 Phantom Unit Plan. On December 31, 2007, 36,200 phantom units vested and $1.6 million was paid out to participants in the first quarter of 2008. At December 31, 2008 and 2007, TEPPCO had accrued liability balances of $0.6 million and $2.6 million, respectively, related to the TEPPCO 2005 Phantom Unit Plan. After the payout in the first quarter of 2009 on awards which vested on December 31, 2008, there will be no remaining phantom units outstanding under the TEPPCO 2005 Phantom Unit Plan. For the years ended December 31, 2008 and 2007, phantom unitholders under the TEPPCO 2005 Phantom Unit Plan received $0.1 million and $0.2 million in cash distributions, respectively.

TEPPCO 2006 LTIP

The TEPPCO 2006 LTIP provides for awards of TEPPCO common units and other rights to its non-employee directors and to certain employees of EPCO working on behalf of TEPPCO. Awards granted under the TEPPCO 2006 LTIP may be in the form of restricted units, phantom units, unit options, UARs and DERs. The TEPPCO 2006 LTIP provides for the issuance of up to 5,000,000 common units of TEPPCO in connection with these awards. After giving effect to outstanding unit options and restricted units at December 31, 2008, and the forfeiture of restricted units through December 31, 2008, a total of 4,487,084 additional units of TEPPCO could be issued under the TEPPCO 2006 LTIP in the future.

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TEPPCO unit options. The information in the following table presents unit option activity under the TEPPCO 2006 LTIP for the periods indicated. No options were exercisable at December 31, 2008.

					Weighted-
			Weighted-		average
			average		remaining
	Number		strike price		contractual
	of units		(dollars/unit)		term (in years)
Option award activity during 2007
Granted (1) (2)		155,000	$	45.35
Outstanding at December 31, 2007		155,000	$	45.35
Granted (3)		200,000	$	35.86
Outstanding at December 31, 2008		355,000	$	40.00		4.57

(1) The total grant date fair value of these awards was $0.4 million based on the following assumptions: (i) expected life of the option of 7 years; (ii) risk-free interest rate of 4.78%; (iii) expected distribution yield on TEPPCO common units of 7.92%; and (iv) expected unit price volatility on TEPPCO’s common units of 18.03%. (2) During 2008, these unit option grants were amended. The expiration dates of these awards granted on May 22, 2007 were modified from May 22, 2017 to December 31, 2012. (3) The total grant date fair value of these awards granted on May 19, 2008 was $0.3 million based on the following assumptions: (i) expected life of the option of 4.7 years; (ii) risk-free interest rate of 3.3%; (iii) expected distribution yield on TEPPCO common units of 7.9%; (iv) estimated forfeiture rate of 17.0% and (v) expected unit price volatility on TEPPCO’s common units of 18.7%.

At December 31, 2008, total unrecognized compensation cost related to nonvested option awards granted under the TEPPCO 2006 LTIP was an estimated $0.6 million. TEPPCO expects to recognize this cost over a weighted-average period of 3.0 years. At December 31, 2007, there was an estimated $0.4 million of total unrecognized compensation cost related to nonvested option awards granted under the TEPPCO 2006 LTIP.

TEPPCO restricted units. The following table summarizes information regarding TEPPCO’s restricted unit awards for the periods indicated:

				Weighted-
				average grant
	Number of			date fair value
	units			per unit (1)
Restricted unit activity during 2007
Granted (2)		62,900		$	37.64
Forfeited		(500	)	$	37.64
Restricted units at December 31, 2007		62,400
Granted (3)		96,900		$	29.54
Vested		(1,000	)	$	40.61
Forfeited		(1,000	)	$	35.86
Restricted units at December 31, 2008		157,300

(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 2007 was $2.4 million based on a grant date market price of TEPPCO’s common units of $45.35 per unit and an estimated forfeiture rate of 17.0%. (3) Aggregate grant date fair value of restricted unit awards issued during 2008 was $2.8 million based on grant date market prices of TEPPCO’s common units ranging from $34.63 to $35.86 per unit and an estimated forfeiture rate of 17.0%.

The total fair value of TEPPCO’s restricted unit awards that vested during the year ended December 31, 2008 was $24 thousand. At December 31, 2008, there was an estimated $3.7 million of total unrecognized compensation cost related to restricted unit awards granted under the TEPPCO 2006 LTIP. TEPPCO expects to recognize these costs over a weighted-average period of 2.8 years. At December 31, 2007, there was an estimated $2.0 million of total unrecognized compensation cost related to restricted unit awards granted under the TEPPCO 2006 LTIP.

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Each recipient of a TEPPCO restricted unit award is 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 TEPPCO to its unitholders. Since restricted units are issued securities of TEPPCO, such distributions are reflected as a component of cash distributions to minority interests as shown on our statements of consolidated cash flows. TEPPCO paid $0.3 million and $0.1 million in cash distributions with respect to its restricted units granted under the TEPPCO 2006 LTIP during the years ended December 31, 2008 and 2007, respectively.

TEPPCO UARs and phantom units. At December 31, 2008, there were a total of 95,654 UARs outstanding that had been granted to non-employee directors of TEPPCO GP and 335,723 UARs outstanding that were granted to certain employees of EPCO who work on behalf of TEPPCO. There were a total of 401,948 UARs outstanding at December 31, 2007. These UAR awards are subject to five year cliff vesting. If the non-employee director or employee resigns prior to vesting, their UAR awards are forfeited. These UAR awards are accounted for similar to liability awards under SFAS 123(R) since they will be settled with cash.

As of December 31, 2008 and 2007, there were a total of 1,647 phantom unit awards outstanding that had been granted to non-employee directors of TEPPCO GP. Each phantom unit will be redeemed in cash the earlier of (i) April 2011 or (ii) when the director is no longer serving on the board of TEPPCO GP. In addition, during the vesting period, each participant is entitled to cash distributions equal to the product of the number of phantom units outstanding for the participant and the cash distribution per unit paid by TEPPCO on its common units. Phantom units awarded to non-employee directors are accounted for similar to liability awards.

The TEPPCO 2006 LTIP provides for the award of DERs in tandem with its phantom unit and UAR awards. With respect to DERs granted in connection with phantom units, the participant is entitled to cash distributions equal to the product of the number of phantom units outstanding for the participant and the cash distribution rate paid by TEPPCO to its unitholders. With respect to DERs granted in connection with UARs, the participant is entitled to the product of the number of UARs outstanding for the participant and the difference between the current declared cash distribution rate paid by TEPPCO and the declared cash distribution rate paid by TEPPCO at the time the UAR was granted. Since phantom units and UARs do not represent issued securities, the cash payments with respect to DERs are expensed by TEPPCO as paid. For the years ended December 31, 2008 and 2007, phantom unitholders under the TEPPCO 2006 LTIP received $4 thousand and $2 thousand in cash distributions, respectively.

Note 7. Employee Benefit Plans

Dixie

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, 2008 and 2007.

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.

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The following table presents Dixie’s benefit obligations, fair value of plan assets and funded status at December 31, 2008:

	Pension			Postretirement
	Plan			Plan
Projected benefit obligation	$	7,733		$	4,976
Accumulated benefit obligation		5,711			--
Fair value of plan assets		4,035			--
Funded status		(3,698	)		(4,976	)

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, 2008 were as follows: discount rate of 6.4%; rate of compensation increase of 4.0% for both the pension and postretirement plans; and a medical trend rate of 8.5% for 2009 grading to an ultimate trend of 5.0% for 2015 and later years. Dixie’s net pension and postretirement benefit costs for 2008 were $0.6 million and $0.4 million, respectively. 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.

Future benefits expected to be paid from Dixie’s pension and postretirement plans are as follows for the periods indicated:

	Pension		Postretirement
	Plan		Plan
2009	$	289	$	357
2010		334		399
2011		535		427
2012		408		440
2013		775		439
2014 through 2017		4,211		2,067
Total	$	6,552	$	4,129

Included in accumulated other comprehensive loss on the Consolidated Balance Sheets at December 31, 2008 and 2007 are the following amounts that have not been recognized in net periodic pension costs (in millions):

	December 31,
	2008			2007
Unrecognized transition obligation	$	0.9		$	1.0
Net of tax		0.5			0.6

Unrecognized prior service cost credit		(1.0	)		(1.2	)
Net of tax		(0.6	)		(0.8	)

Unrecognized net actuarial loss		1.3			2.8
Net of tax		0.8			1.7

Terminated Plans - TEPPCO

Prior to April 2006, TEPPCO maintained a Retirement Cash Balance Plan (the “RCBP”), which was a non-contributory, trustee-administered pension plan. In April 2006, TEPPCO received a determination letter from the Internal Revenue Service providing its approval to terminate the plan.

In 2007 and 2006, TEPPCO recorded settlement charges of approximately $0.1 million and $3.5 million, respectively, in connection with the plan’s termination and distribution of assets to plan participants. At December 31, 2008, all benefit obligations to plan participants have been settled. Net pension benefit costs for the RCBP were $0.2 million for the year ended December 31, 2007.

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Note 8. Financial Instruments

The following table presents gains (losses) recorded in net income attributable to our interest rate risk and commodity risk hedging transactions for the periods indicated. These amounts do not present the corresponding gains (losses) attributable to the underlying hedged items.

	For the Year Ended December 31,
	2008			2007			2006
Interest Rate Risk Hedging Portfolio:
Parent Company:
Ineffective portion of cash flow hedges	$	866		$	(2,127	)	$	--
Reclassification of cash flow hedge amounts from AOCI, net		(6,610	)		742			--
Enterprise Products Partners (excluding Duncan Energy Partners):
Reclassification of cash flow hedge amounts from AOCI, net		4,409			5,429			4,234
Other gains (losses) from derivative transactions		5,340			(8,934	)		(5,195	)
Duncan Energy Partners:
Ineffective portion of cash flow hedges		(5	)		(155	)		--
Reclassification of cash flow hedge amounts from AOCI, net		(2,008	)		350			--
TEPPCO:
Ineffective portion of cash flow hedges		(43	)		--			--
Reclassification of cash flow hedge amounts from AOCI, net		(4,924	)		64			--
Loss from treasury lock cash flow hedge		(3,586	)		--			--
Other gains from derivative transactions		4,056			5,202			8,568
Total hedging gains (losses), net, in consolidated interest expense	$	(2,505	)	$	571		$	7,607

Commodity Risk Hedging Portfolio:
Enterprise Products Partners:
Reclassification of cash flow hedge amounts from AOCI, net - natural gas marketing activities	$	(30,175	)	$	(3,299	)	$	(1,327	)
Reclassification of cash flow hedge amounts from AOCI, net - NGL and petrochemical operations		(28,232	)		(4,564	)		13,891
Other gains (losses) from derivative transactions		29,772			(20,712	)		(2,307	)
TEPPCO:
Reclassification of cash flow hedge amounts from AOCI, net		(37,898	)		(1,654	)		261
Other gains (losses) from derivative transactions		(343	)		189			(96	)
Total hedging gains (losses), net, in consolidated operating costs and expenses	$	(68,876	)	$	(30,040	)	$	10,422

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The following table provides additional information regarding derivative assets and derivative liabilities included in our Consolidated Balance Sheets at the dates indicated:

	At December 31,
	2008		2007
Current assets:
Derivative assets:
Interest rate risk hedging portfolio	$	7,780	$	637
Commodity risk hedging portfolio		201,473		10,796
Foreign currency risk hedging portfolio		9,284		1,308
Total derivative assets – current	$	218,537	$	12,741
Other assets:
Interest rate risk hedging portfolio	$	38,939	$	14,744
Total derivative assets – long-term	$	38,939	$	14,744

Current liabilities:
Derivative liabilities:
Interest rate risk hedging portfolio	$	19,205	$	49,689
Commodity risk hedging portfolio		296,850		48,930
Foreign currency risk hedging portfolio		109		27
Total derivative liabilities – current	$	316,164	$	98,646
Other liabilities:
Interest rate risk hedging portfolio	$	17,131	$	13,047
Commodity risk hedging portfolio		233		--
Total derivative liabilities– long-term	$	17,364	$	13,047

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The following table presents gains (losses) recorded in other comprehensive income (loss) for cash flow hedges associated with our interest rate risk, commodity risk and foreign currency risk hedging portfolios. These amounts do not present the corresponding gains (losses) attributable to the underlying hedged items.

	For the Year Ended December 31,
	2008			2007			2006
Interest Rate Risk Hedging Portfolio:
Parent Company:
Losses on cash flow hedges	$	(21,178	)	$	(9,284	)	$	--
Reclassification of cash flow hedge amounts to net income, net		6,610			(742	)		--
Enterprise Products Partners (excluding Duncan Energy Partners):
Gains (losses) on cash flow hedges		(20,772	)		17,996			11,196
Reclassification of cash flow hedge amounts to net income, net		(4,409	)		(5,429	)		(4,234	)
Duncan Energy Partners:
Losses on cash flow hedges		(7,989	)		(3,271	)		--
Reclassification of cash flow hedge amounts to net income, net		2,008			(350	)		--
TEPPCO:
Losses on cash flow hedges		(26,802	)		(23,604	)		(248	)
Reclassification of cash flow hedge amounts to net income, net		4,924			(64	)		--
Total interest rate risk hedging gains (losses), net		(67,608	)		(24,748	)		6,714
Commodity Risk Hedging Portfolio:
Enterprise Products Partners:
Natural gas marketing activities:
Gains (losses) on cash flow hedges		(30,642	)		(3,125	)		(1,034	)
Reclassification of cash flow hedge amounts to net income, net		30,175			3,299			1,327
NGL and petrochemical operations:
Gains (losses) on cash flow hedges		(120,223	)		(22,735	)		9,975
Reclassification of cash flow hedge amounts to net income, net		28,232			4,564			(13,891	)
TEPPCO:
Gains (losses) on cash flow hedges		(19,257	)		(21,036	)		991
Reclassification of cash flow hedge amounts to net income, net		37,898			1,654			(261	)
Total commodity risk hedging losses, net		(73,817	)		(37,379	)		(2,893	)
Foreign Currency Risk Hedging Portfolio:
Gains on cash flow hedges		9,287			1,308			--
Total foreign currency risk hedging gains, net		9,287			1,308			--
Total cash flow hedge amounts in other comprehensive income (loss)	$	(132,138	)	$	(60,819	)	$	3,821

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Interest Rate Risk Hedging Portfolio

The following information summarizes significant components of our interest rate risk hedging portfolio:

	Number	Period Covered	Termination	Variable to	Notional
Hedged Variable Rate Debt	of Swaps	by Swap	Date of Swap	Fixed Rate (1)	Value
Parent Company variable-rate borrowings	2	Aug. 2007 to Aug. 2009	Aug. 2009	4.32% to 5.01%	$250.0 million
Parent Company variable-rate borrowings	2	Sep. 2007 to Aug. 2011	Aug. 2011	4.32% to 4.82%	$250.0 million

(1) Amounts receivable from or payable to the swap counterparties are settled every three months (the “settlement period”).

The Parent Company expects to reclassify $14.6 million of cumulative net losses from its cash flow hedges into net income (as an increase to interest expense) during 2009.

Enterprise Products Partners. Enterprise Products Partners’ interest rate exposure results from variable and fixed rate borrowings under various debt agreements.

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Enterprise Products Partners expects to reclassify $1.6 million of cumulative net gains from its interest rate risk cash flow hedges into net income (as a decrease to interest expense) during 2009.

TEPPCO expects to reclassify $5.8 million of cumulative net losses from its interest rate risk cash flow hedges into net income (as an increase to interest expense) during 2009.

Commodity Risk Hedging Portfolio

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Natural gas marketing activities

At December 31, 2008 and 2007, the aggregate fair value of those financial instruments utilized in connection with Enterprise Products Partners’ natural gas marketing activities was an asset of $6.5 million and a liability of $0.3 million, respectively. Enterprise Products Partners’ natural gas marketing business and its related use of financial instruments has increased significantly during 2008. Almost all of the financial instruments within this portion of the commodity financial instruments portfolio are accounted for using mark-to-market accounting, with a small number accounted for as cash flow hedges. Enterprise Products Partners did not have any cash flow hedges outstanding related to its natural gas marketing activities at December 31, 2008.

NGL and petrochemical operations

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based on the higher market price. The net effect of these hedging relationships is that Enterprise Products Partners’ total cost of natural gas used for PTR approximates the amount it originally hedged under this program.

Foreign Currency Hedging Program – Enterprise Products Partners

Fair Value Information

Cash and cash equivalents (including restricted cash), 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 commodity, foreign currency and interest rate hedging portfolios were developed using available market information and appropriate valuation techniques.

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The following table presents the estimated fair values of our financial instruments at the dates indicated:

	At December 31, 2008				At December 31, 2007
	Carrying		Fair		Carrying		Fair
Financial Instruments	Value		Value		Value		Value
Financial assets:
Cash and cash equivalents, including restricted cash	$	260,617	$	260,617	$	95,064	$	95,064
Accounts receivable		2,028,640		2,028,640		3,365,290		3,365,290
Commodity financial instruments (1)		201,473		201,473		10,796		10,796
Foreign currency hedging financial instruments (2)		9,284		9,284		1,308		1,308
Interest rate hedging financial instruments (3)		46,719		46,719		15,093		15,093
Financial liabilities:
Accounts payable and accrued expenses		2,507,842		2,507,842		4,218,553		4,218,553
Fixed-rate debt (principal amount) (4)		9,704,296		8,192,172		7,259,000		7,238,729
Variable-rate debt		2,935,403		2,935,403		2,572,500		2,572,500
Commodity financial instruments (1)		297,083		297,083		48,998		48,998
Foreign currency hedging financial instruments (2)		109		109		27		27
Interest rate hedging financial instruments (3)		36,336		36,336		60,870		60,870

(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 Enterprise Products Partners’ 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. (4) Due to the distress in the capital markets following the collapse of several major financial entities and uncertainty in the credit markets during 2008, corporate debt securities were trading at significant discounts.

Adoption of SFAS 157 - Fair Value Measurements. On January 1, 2008, we adopted the provisions of SFAS 157 that apply to financial assets and liabilities. We adopted the provisions of SFAS 157 that apply to nonfinancial assets and liabilities on January 1, 2009. SFAS 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date.

Our fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability. These assumptions include estimates of risk. Recognized valuation techniques employ inputs such as product prices, operating costs, discount factors and business growth rates. These inputs may be either readily observable, corroborated by market data or generally unobservable. In developing our estimates of fair value, we endeavor to utilize the best information available and apply market-based data to the extent possible. Accordingly, we utilize valuation techniques (such as the market approach) that maximize the use of observable inputs and minimize the use of unobservable inputs.

SFAS 157 established a three-tier hierarchy that classifies fair value amounts recognized or disclosed in the financial statements based on the observability of inputs used to estimate such fair values. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, we categorize our financial assets and liabilities using this hierarchy. The characteristics of fair value amounts classified within each level of the SFAS 157 hierarchy are described as follows:

Level 1 fair values are based on quoted prices, which are available in active markets for identical assets or liabilities as of the measurement date. Active markets are defined as those in which transactions for identical assets or liabilities occur in sufficient frequency so as to provide pricing information on an ongoing basis (e.g., the NYSE or NYMEX). Level 1 primarily consists of financial assets and liabilities such as exchange-traded financial instruments, publicly-traded equity securities and U.S. government treasury securities.

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Level 2 fair values are based on pricing inputs other than quoted prices in active markets (as reflected in Level 1 fair values) and are either directly or indirectly observable as of the measurement date. Level 2 fair values include instruments that are valued using financial models or other appropriate valuation methodologies. Such financial models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value of money, volatility factors for stocks and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are (i) observable in the marketplace throughout the full term of the instrument, (ii) can be derived from observable data or (iii) are validated by inputs other than quoted prices (e.g., interest rate and yield curves at commonly quoted intervals). Level 2 includes non-exchange-traded instruments such as over-the-counter forward contracts, options and repurchase agreements.

Level 3 fair values are based on unobservable inputs. Unobservable inputs are used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. Unobservable inputs reflect the reporting entity’s own ideas about the assumptions that market participants would use in pricing an asset or liability (including assumptions about risk). Unobservable inputs are based on the best information available in the circumstances, which might include the reporting entity’s internally-developed data. The reporting entity must not ignore information about market participant assumptions that is reasonably available without undue cost and effort. Level 3 inputs are typically used in connection with internally developed valuation methodologies where management makes its best estimate of an instrument’s fair value. Level 3 generally includes specialized or unique financial instruments that are tailored to meet a customer’s specific needs. At December 31, 2008, our Level 3 financial assets consisted largely of ethane based contracts with a range of two to twelve months in term. This classification is primarily due to our reliance on broker quotes for this product due to the forward ethane markets being less than highly active.

The following table sets forth, by level within the fair value hierarchy, our financial assets and liabilities measured on a recurring basis at December 31, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Level 1		Level 2		Level 3		Total
Financial assets:
Commodity financial instruments	$	4,030	$	164,668	$	32,775	$	201,473
Foreign currency financial instruments		--		9,284		--		9,284
Interest rate financial instruments		--		46,719		--		46,719
Total	$	4,030	$	220,671	$	32,775	$	257,476

Financial liabilities:
Commodity financial instruments	$	7,137	$	289,576	$	370	$	297,083
Foreign currency financial instruments		--		109		--		109
Interest rate financial instruments		--		36,336		--		36,336
Total	$	7,137	$	326,021	$	370	$	333,528
Net financial assets, Level 3					$	32,405

Fair values associated with our interest rate, commodity and foreign currency financial instrument portfolios were developed using available market information and appropriate valuation techniques in accordance with SFAS 157.

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The following table sets forth a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities during the year ended December 31, 2008:

Balance, January 1, 2008	$	(5,054	)
Total gains (losses) included in:
Net income (1)		(34,560	)
Other comprehensive loss		37,212
Purchases, issuances, settlements		34,807
Balance, December 31, 2008	$	32,405

(1) There were unrealized gains of $0.2 million included in net income for the year ended December 31, 2008.

Note 9. Cumulative Effect of Change in Accounting Principle

Upon adoption of SFAS 123(R), we recognized, as a benefit, the cumulative effect of a change in accounting principle of $1.5 million, of which $1.4 million was allocated to minority interest in our consolidated financial statements.

SFAS 123(R) requires us to recognize compensation expense related to equity awards based on the fair value of the award at grant date. The fair value of restricted unit awards is based in the market price of the underlying common units on the date of grant. The fair value of other equity awards is estimated using the Black-Scholes option pricing model. Under SFAS 123(R), the fair value of an equity award is amortized to earnings on a straight-line basis over the requisite service or vesting period for equity 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.

On a pro forma consolidated basis, our net income and earnings for Unit amount would not have differed materially from those we actually reported in 2006 due to the immaterial nature of this cumulative effect of change in accounting principle.

See Note 6 for additional information regarding our accounting for equity awards.

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Note 10. Inventories

Our inventory amounts by business segment were as follows at the dates indicated:

	December 31,
	2008			2007
Investment in Enterprise Products Partners:
Working inventory (1)	$	200,439		$	342,589
Forward sales inventory (2)		162,376			11,693
Subtotal		362,815			354,282
Investment in TEPPCO:
Working inventory (3)		13,617			56,574
Forward sales inventory (4)		30,709			16,547
Subtotal		44,326			73,121
Eliminations		(2,136	)		(1,717	)
Total inventory	$	405,005		$	425,686

(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 identified NGL and natural gas volumes dedicated to the fulfillment of forward sales contracts. (3) Working inventory is comprised of inventories of crude oil, refined products, LPGs, lubrication oils, and specialty chemicals that are either available-for-sale or used in the provision for services. (4) Forward sales inventory primarily consists of identified crude oil 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. Inventories are valued at the lower of average cost or market.

In addition to cash purchases, Enterprise Products Partners takes ownership of volumes through percent-of-liquids contracts and similar arrangements. These volumes are recorded as inventory at market-related values in the month of acquisition. Enterprise Products Partners capitalizes as a component of inventory those ancillary costs (e.g. freight-in, handling and processing charges) incurred in connection with such volumes.

Our cost of sales amounts are a component of “Operating costs and expenses” as presented in our Consolidated Statements of Operations. Due to fluctuating commodity prices, we recognize lower of cost or market (“LCM”) adjustments when the carrying value of inventories exceeds their net realizable value. These non-cash charges are a component of cost of sales. To the extent our commodity hedging strategies address inventory-related risks and are successful, these inventory valuation adjustments are mitigated or offset. See Note 8 for a description of our commodity hedging activities. The following table presents cost of sales amounts by segment for the periods noted:

	For Year Ended December 31,
	2008			2007			2006

Investment in Enterprise Products Partners (1)	$	18,662,263		$	14,509,220		$	11,778,928
Investment in TEPPCO (2)		12,733,695			9,074,297			8,999,670
Eliminations		(191,149	)		(89,538	)		(65,412	)
Total cost of sales	$	31,204,809		$	23,493,979		$	20,713,186

(1) Includes LCM adjustments of $50.7 million, $13.3 million and $18.6 million recognized during the years ended December 31, 2008, 2007 and 2006, respectively. (2) Includes LCM adjustments of $12.3 million, $0.8 million and $1.7 million for the years ended December 31, 2008, 2007, and 2006, respectively.

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Note 11. Property, Plant and Equipment

Our property, plant and equipment amounts by business segment were as follows at the dates indicated:

	Estimated
	Useful Life	December 31,
	In Years	2008		2007
Investment in Enterprise Products Partners:
Plants, pipelines, buildings and related assets (1)	3-40 (5)	$	12,284,921	$	10,873,422
Storage facilities (2)	5-35 (6)		900,664		720,795
Offshore platforms and related facilities (3)	20-31		634,761		637,812
Transportation equipment (4)	3-10		38,771		32,627
Land			54,627		48,172
Construction in progress			1,695,298		1,173,988
Total historical cost			15,609,042		13,486,816
Less accumulated depreciation			2,374,987		1,910,848
Total carrying value, net			13,234,055		11,575,968
Investment in TEPPCO:
Plants, pipelines, buildings and related assets (1)	5-40 (5)		2,972,503		2,511,714
Storage facilities (2)	5-40 (6)		303,174		260,860
Transportation equipment (4)	5-10		12,140		8,370
Marine vessels (7)	20-30		453,041		--
Land			199,944		172,348
Construction in progress			319,368		414,265
Total historical cost			4,260,170		3,367,557
Less accumulated depreciation			770,825		644,129
Total carrying value, net			3,489,345		2,723,428
Total property, plant and equipment, net		$	16,723,400	$	14,299,396

(1) Includes processing plants; NGL, crude oil, natural gas and other pipelines; terminal loading and unloading facilities; buildings; office furniture and equipment; laboratory and shop equipment; and related assets. (2) Includes underground product storage caverns, above ground storage tanks, water wells and related assets. (3) Includes offshore platforms and related facilities and assets. (4) Includes vehicles and similar assets used in our operations. (5) In general, the estimated useful lives of major components of this category approximate the following: processing plants, 20-35 years; pipelines and related equipment, 5-40 years; terminal facilities, 10-35 years; delivery facilities, 20-40 years; buildings, 20-40 years; office furniture and equipment, 3-20 years; and laboratory and shop equipment, 5-35 years. (6) In general, the estimated useful lives of major components of this category approximate the following: underground storage facilities, 5-35 years; storage tanks 10-40 years; and water wells, 5-35 years. (7) See Note 13 for additional information regarding the acquisition of marine services businesses by TEPPCO in February 2008.

The following table summarizes our depreciation expense and capitalized interest amounts by segment for the periods noted:

	For Year Ended December 31,
	2008		2007		2006
Investment in Enterprise Products Partners:
Depreciation expense (1)	$	465,851	$	414,742	$	352,227
Capitalized interest (2)		71,584		75,476		55,660
Investment in TEPPCO:
Depreciation expense (1)		129,675		100,650		82,404
Capitalized interest (2)		19,117		11,030		10,681
(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.

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Enterprise Products Partners reviewed assumptions underlying the estimated remaining useful lives of certain of its assets during the first quarter of 2008. As a result of this review, effective January 1, 2008, Enterprise Products Partners revised the remaining useful lives of these assets, most notably the assets that constitute its Texas Intrastate System. This revision increased the remaining useful life of such assets to incorporate recent data showing that proved natural gas reserves supporting throughput and processing volumes for these assets have changed since Enterprise Products Partners’ original determination made in September 2004. These revisions will prospectively reduce Enterprise Products Partners’ depreciation expense on assets having carrying values totaling $2.72 billion as of January 1, 2008. On average, we extended the life of these assets by 3.1 years. As a result of this change in estimate, depreciation expense included in operating income for the year ended December 31, 2008 decreased by approximately $20.0 million. Of this amount, $19.0 million was attributed to minority interest. The impact of this change in estimate on our earnings per unit was immaterial.

Asset retirement obligations

We have recorded AROs related to legal requirements to perform retirement activities as specified in contractual arrangements and/or governmental regulations. On a consolidated basis, our property, plant and equipment at December 31, 2008 and 2007 includes $11.7 million and $11.3 million, respectively, of asset retirement costs capitalized as an increase in the associated long-lived asset. We estimate that accretion expense will approximate $2.3 million for 2009, $2.4 million for 2010, $2.6 million for 2011, $2.9 million for 2012 and $3.1 million for 2013.

The following table summarizes amounts recognized in connection with AROs by segment since December 31, 2006:

	Investment in
	Enterprise
	Products			Investment in
	Partners			TEPPCO			Total
ARO liability balance, December 31, 2006	$	24,403		$	1,419		$	25,822
Liabilities incurred		1,673			48			1,721
Liabilities settled		(5,069	)		--			(5,069	)
Revisions in estimated cash flows		15,645			--			15,645
Accretion expense		3,962			143			4,105
ARO liability balance, December 31, 2007		40,614			1,610			42,224
Liabilities incurred		1,064			--			1,064
Liabilities settled		(7,229	)		(1,012	)		(8,241	)
Revisions in estimated cash flows		1,163			3,589			4,752
Accretion expense		2,114			326			2,440
ARO liability balance, December 31, 2008	$	37,726		$	4,513		$	42,239

Enterprise Products Partners. The liabilities associated with Enterprise Products Partners’ AROs primarily relate to (i) right-of-way agreements associated with its 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, Enterprise Products Partners’ AROs may result from the renovation or demolition of certain assets containing hazardous substances such as asbestos.

TEPPCO. In general, the liabilities associated with TEPPCO’s AROs primarily relate to (i) right-of-way agreements for its pipeline operations and (ii) leases of plant sites and office space.

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Note 12. 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 4 for a general discussion of our business segments. The following table shows our investments in and advances to unconsolidated affiliates by segment at the dates indicated:

	Ownership
	Percentage at
	December 31,	December 31,
	2008	2008		2007
Investment in Enterprise Products Partners:
Venice Energy Service Company, L.L.C. (“VESCO”)	13.1%	$	37,673	$	40,129
K/D/S Promix, L.L.C. (“Promix”)	50.0%		46,383		51,537
Baton Rouge Fractionators LLC (“BRF”)	32.2%		24,160		25,423
White River Hub, LLC (“White River Hub”) (1)	50.0%		21,387		--
Skelly-Belvieu Pipeline Company, L.L.C. (“Skelly-Belvieu”) (2)	49.0%		35,969		--
Evangeline (3)	49.5%		4,528		3,490
Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”)	36.0%		60,233		58,423
Cameron Highway Oil Pipeline Company (“Cameron Highway”)	50.0%		250,833		256,588
Deepwater Gateway, L.L.C. (“Deepwater Gateway”)	50.0%		104,785		111,221
Neptune	25.7%		52,671		55,468
Nemo	33.9%		432		2,888
Baton Rouge Propylene Concentrator LLC (“BRPC”)	30.0%		12,633		13,282
Other	50.0%		3,887		4,053
Total Investment in Enterprise Products Partners			655,574		622,502
Investment in TEPPCO:
Seaway Crude Pipeline Company (“Seaway”)	50.0%		186,224		184,757
Centennial Pipeline LLC (“Centennial”)	50.0%		69,696		77,919
Other	25.0%		332		362
Total Investment in TEPPCO			256,252		263,038
Investment in Energy Transfer Equity:
Energy Transfer Equity	17.5%		1,587,115		1,641,363
LE GP	34.9%		11,761		12,100
Total Investment in Energy Transfer Equity			1,598,876		1,653,463
Total consolidated		$	2,510,702	$	2,539,003

(1) In February 2008, Enterprise Products Partners acquired a 50.0% ownership interest in White River Hub. (2) In December 2008, Enterprise Products Partners acquired a 49.0% ownership interest in Skelly-Belvieu. (3) Refers to ownership interests in Evangeline Gas Pipeline Company, L.P. and Evangeline Gas Corp., collectively.

On occasion, the price we pay to acquire a non-controlling ownership interest in a company exceeds the underlying book value of the net assets we acquire. Such excess cost amounts are included within the carrying values of our investments in and advances to unconsolidated affiliates. That portion of excess cost attributable to fixed assets or amortizable intangible assets is amortized over the estimated useful life of the underlying asset(s) as a reduction in equity earnings from the entity. That portion of excess cost attributable to goodwill or indefinite life intangible assets is not subject to amortization. Equity method investments, including their associated excess cost amounts, are evaluated for impairment whenever events or changes in circumstances indicate that there is a loss in value of the investment which is other than temporary.

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The following table summarizes our excess cost information at the dates indicated by business segment:

	Investment in				Investment in
	Enterprise				Energy
	Products		Investment in		Transfer
	Partners		TEPPCO		Equity		Total
Initial excess cost amounts attributable to:
Fixed Assets	$	51,476	$	30,277	$	576,626	$	658,379
Goodwill		--		--		335,758		335,758
Intangibles – finite life		--		30,021		244,695		274,716
Intangibles – indefinite life		--		--		513,508		513,508
Total	$	51,476	$	60,298	$	1,670,587	$	1,782,361

Excess cost amounts, net of amortization at:
December 31, 2008	$	34,272	$	28,350	$	1,609,575	$	1 672 197
December 31, 2007	$	36,156	$	33,302	$	1,643,890	$	1,713,348

As shown in the preceding table, the Parent Company’s initial investments in Energy Transfer Equity and LE GP exceeded its share of the historical cost of the underlying net assets of such investees by $1.67 billion. At December 31, 2008, this basis differential decreased to $1.61 billion (after taking into account related amortization amounts) and consisted of the following:

§	$537.6 million attributed to fixed assets;

§	$513.5 million attributed to the IDRs (an indefinite-life intangible asset) held by Energy Transfer Equity in the cash flows of ETP;

§	$222.7 million attributed to amortizable intangible assets;

§	and $335.8 million attributed to equity method goodwill.

The basis differential amounts attributed to fixed assets and amortizable intangible assets represent the Parent Company’s pro rata share of the excess of the fair values determined for such assets over the investee’s historical carrying values for such assets at the date the Parent Company acquired its investments in Energy Transfer Equity and LE GP. These excess cost amounts are being amortized over the estimated useful life of the underlying assets. We estimate such non-cash amortization expense to be $36.6 million for each of the years 2009 through 2011, $36.3 million in 2012 and $36.1 million for 2013.

The $513.5 million of excess cost attributed to ETP’s IDRs represents the Parent Company’s pro rata share of the fair value of the incentive distribution rights held by Energy Transfer Equity in ETP’s cash distributions. The $335.8 million of equity method goodwill is attributed to our view of the future financial performance of Energy Transfer Equity and LE GP based upon their underlying assets and industry relationships. Excess cost amounts attributed to the ETP IDRs and the equity method goodwill are not amortized; however, such amounts are subject to impairment testing.

Amortization of excess cost amounts are recorded as a reduction in equity earnings. The following table summarizes our excess cost amortization by segment for the periods indicated:

	For Year Ended December 31,
	2008		2007		2006

Investment in Enterprise Products Partners	$	1,884	$	2,499	$	2,052
Investment in TEPPCO		4,952		5,967		4,318
Investment in Energy Transfer Equity		34,315		26,697		--
Total excess cost amortization (1)	$	41,151	$	35,163	$	6,370

(1) As of December 31, 2008, we expect that our total annual excess cost amortization will be as follows: $43.8 million in 2009; $39.3 million in each of 2010 and 2011; $39.0 million in 2012; and $38.8 million in 2013.

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Equity earnings from our Investment in Energy Transfer Equity segment for the year ended December 31, 2008 were $65.6 million, before $34.3 million of amortization of excess cost amounts. Equity earnings from our Investment in Energy Transfer Equity segment for the year ended December 31, 2007 were $29.8 million, before $26.7 million of amortization of excess cost amounts.

The following table presents our equity in earnings from unconsolidated affiliates for the periods indicated:

	For Year Ended December 31,
	2008			2007			2006
Investment in Enterprise Products Partners:
VESCO	$	(1,519	)	$	3,507		$	1,719
Promix		1,977			514			1,353
BRF		1,003			2,010			2,643
Skelly-Belvieu		(31	)		--			--
Evangeline		896			183			958
White River Hub		655			--			--
Poseidon		6,883			10,020			11,310
Cameron Highway		16,358			(11,200	)		(11,000	)
Deepwater Gateway		17,062			20,606			18,392
Neptune (1)		(5,683	)		(821	)		(8,294	)
Nemo (2)		(973	)		(5,977	)		1,501
BRPC		1,877			2,266			1,864
Other		(771	)		(807	)		881
Subtotal equity in earnings		37,734			20,301			21,327
Investment in TEPPCO:
Seaway		11,732			2,602			11,905
Centennial (3)		(14,673	)		(13,528	)		(17,101	)
MB Storage (4)		--			1,090			9,082
Other		70			43			--
Subtotal equity in earnings		(2,871	)		(9,793	)		3,886
Investment in Energy Transfer Equity:
Energy Transfer Equity		31,146			3,109			--
LE GP		152			(14	)		--
Subtotal equity in earnings		31,298			3,095			--
Total equity in earnings	$	66,161		$	13,603		$	25,213

(1) Equity in earnings from Neptune for 2006 include a $7.4 million non-cash impairment charge. (2) Equity in earnings from Nemo for 2007 include a $7.0 million non-cash impairment charge. (3) Equity in earnings from Centennial reflect significant intercompany eliminations due to transactions between TEPPCO and Centennial. See “Investment in TEPPCO – Centennial” within this Note 12 for additional information regarding these amounts. (4) Refers to ownership interests in Mont Belvieu Storage Partners, L.P. and Mont Belvieu Venture, LLC, collectively. TEPPCO disposed of this investment on March 1, 2007.

We monitor the underlying business fundamentals of our investments in unconsolidated affiliates and test such investments for impairment when impairment indicators are present. As a result of our reviews for the year ended December 31, 2008, no impairment charges were required. We have the intent and ability to hold our equity method investments, which are integral to our operations.

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Investment in Enterprise Products Partners

The combined balance sheet information and results of operations data of this segment’s current unconsolidated affiliates are summarized below.

	December 31,
	2008		2007
Balance Sheet Data:
Current assets	$	196,634	$	187,790
Property, plant and equipment, net		1,565,913		1,404,708
Other assets		23,102		37,209
Total assets	$	1,785,649	$	1,629,707
Current liabilities	$	139,189	$	116,682
Other liabilities		162,439		130,626
Combined equity		1,484,021		1,382,399
Total liabilities and combined equity	$	1,785,649	$	1,629,707

	For Year Ended December 31,
	2008		2007		2006
Income Statement Data:
Revenues	$	828,697	$	669,936	$	655,405
Operating income		102,138		138,995		61,296
Net income		94,353		86,496		27,236

At December 31, 2008, our Investment in Enterprise Products Partners segment included the following unconsolidated affiliates accounted for using the equity method:

VESCO. Enterprise Products Partners owns a 13.1% interest in VESCO, which owns a natural gas processing facility and related assets located in south Louisiana.

Promix. Enterprise Products Partners owns a 50.0% interest in Promix, which owns an NGL fractionation facility and related storage and pipeline assets located in south Louisiana.

BRF. Enterprise Products Partners owns an approximate 32.3% interest in BRF, which owns an NGL fractionation facility located in south Louisiana.

Evangeline. Duncan Energy Partners owns an approximate 49.5% aggregate interest in Evangeline, which owns a natural gas pipeline located in south Louisiana. See Note 15 for information regarding the debt obligations of this unconsolidated affiliate.

White River Hub. Enterprise Products Partners owns a 50.0% interest in White River Hub, which owns a natural gas hub located in northwest Colorado. The hub was completed in December 2008.

Skelly-Belvieu. In December 2008, Enterprise Products Partners acquired a 49.0% interest in Skelly-Belvieu for $36.0 million. Skelly-Belvieu owns a 570-mile pipeline that transports mixed NGLs to markets in southeast Texas.

Poseidon. Enterprise Products Partners owns 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. See Note 15 for information regarding the debt obligations of this unconsolidated affiliate.

Cameron Highway. Enterprise Products Partners owns 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.

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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. Enterprise Products Partners funded its 50% share of the capital contributions using borrowings under EPO’s Revolver. Cameron Highway incurred a $14.1 million make-whole premium in connection with the repayment of its Series A notes.

Deepwater Gateway. Enterprise Products Partners owns 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. Enterprise Products Partners owns 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. 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 decrease in throughput volumes on the Manta Ray and Nautilus pipelines, Enterprise Products Partners evaluated its 25.7% investment in Neptune for impairment in 2006. The decrease in throughput volumes was attributable 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 experienced operating losses. Enterprise Products Partners’ review of Neptune’s estimated cash flows indicated that the carrying value of its 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 earnings of unconsolidated affiliates” in our Statement of Consolidated Operations for the year ended December 31, 2006.

Nemo. Enterprise Products Partners owns a 33.9% interest in Nemo, which owns the Nemo Gathering System, which is a natural gas pipeline located in the Gulf of Mexico. The Nemo Gathering System 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 decrease in throughput volumes on the Nemo Gathering System, Enterprise Products Partners evaluated its investment in Nemo for impairment in 2007. The decrease in throughput volumes was primarily due to underperformance of certain fields and natural depletion. Enterprise Products Partners’ review of Nemo’s estimated future cash flows in 2007 indicated that the carrying value of its 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 earnings of unconsolidated affiliates” in our Statements of Consolidated Operations for the year ended December 31, 2007.

Enterprise Products Partners’ investments in Neptune and Nemo were written down to their respective fair values, which management estimated using recognized business valuation techniques. If the assumptions underlying such fair values change and expected cash flows are reduced, additional impairment charges for these investments may result in the future.

BRPC. Enterprise Products Partners owns a 30.0% interest in BRPC, which owns a propylene fractionation facility located in south Louisiana.

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Investment in TEPPCO

The combined balance sheet information and results of operations data of this segment’s current unconsolidated affiliates (i.e. Seaway and Centennial) are summarized below.

	December 31,
	2008			2007
Balance Sheet Data:
Current assets	$	44,161		$	37,293
Property, plant and equipment, net		487,426			500,530
Other assets		(4	)		1
Total assets	$	531,583		$	537,824
Current liabilities	$	26,798		$	30,271
Other liabilities		120,380			130,303
Combined equity		384,405			377,250
Total liabilities and combined equity	$	531,583		$	537,824

	For Year Ended December 31,
	2008		2007		2006
Income Statement Data:
Revenues	$	132,987	$	124,153	$	160,408
Operating income		52,266		34,422		44,580
Net income		41,655		23,954		34,070

At December 31, 2008, our Investment in TEPPCO segment included the following unconsolidated affiliates accounted for using the equity method:

Seaway. TEPPCO owns a 50% interest in Seaway, which owns a pipeline that transports crude oil from a marine terminal located at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal located at Texas City, Texas, to refineries in the Texas City and Houston, Texas areas.

Centennial. TEPPCO owns a 50% interest in Centennial, which owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Prior to April 2002, TEPPCO’s mainline pipeline was bottlenecked between Beaumont, Texas and El Dorado, Arkansas, which limited TEPPCO’s ability to transport refined products and LPGs during peak periods. When the Centennial pipeline commenced operations in 2002, it effectively looped TEPPCO’s mainline, thus providing TEPPCO incremental transportation capacity into Mid-continent markets. Centennial is a key investment of TEPPCO.

Since TEPPCO utilizes the Centennial pipeline in its mainline operations, TEPPCO’s equity earnings from Centennial reflect the elimination of profits and losses attributable to intercompany transactions. Such eliminations reduced equity earnings as follows for the periods noted: $8.1 million for the year ended December 31, 2008; $9.6 million for the year ended December 31, 2007; and $5.6 million for the year ended December 31, 2006. Additionally, TEPPCO amortizes its excess cost in Centennial, which reduced equity in earnings by $4.3 million, $5.4 million and $3.6 million for the years ended December 31, 2008, 2007 and 2006, respectively.

MB Storage. On March 1, 2007, TEPPCO sold its 49.5% ownership interest in Mont Belvieu Storage Partners, L.P. (“MB Storage”) and its 50% ownership interest in Mont Belvieu Venture, LLC (the general partner of MB Storage) to Louis Dreyfus Energy Services L.P. for approximately $156.0 million in cash. TEPPCO recognized a gain of approximately $60.0 million related to its sale of these equity interests, which is included in other income for the year ended December 31, 2007. The sale of MB Storage was required by the U.S. Federal Trade Commission (“FTC”) in connection with ending its investigation into the acquisition of TEPPCO GP by private company affiliates of EPCO in February 2005.

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Investment in Energy Transfer Equity

This segment reflects the Parent Company’s non-controlling ownership interests in Energy Transfer Equity and its general partner, LE GP, both of which are accounted for using the equity method. In May 2007, the Parent Company paid $1.65 billion to acquire 38,976,090 common units of Energy Transfer Equity and approximately 34.9% of the membership interests of LE GP. The following table summarizes the values recorded by the Parent Company in connection with its purchase of these equity interests.

Energy Transfer Equity (38,976,090 common units)	$	1,636,996
LE GP (approximately 34.9% membership interest)		12,338
Total invested by the Parent Company	$	1,649,334

On January 22, 2009, the Parent Company acquired an additional 5.7% membership interest in LE GP for $0.8 million, which increased our total ownership in LE GP to 40.6%.

LE GP. The business purpose of LE GP is to manage the affairs and operations of Energy Transfer Equity. LE GP has no separate business activities outside of those conducted by Energy Transfer Equity. LE GP owns a 0.31% general partner interest in Energy Transfer Equity and has no IDR’s in the quarterly cash distributions of Energy Transfer Equity.

Energy Transfer Equity. Energy Transfer Equity currently has no separate operating activities apart from those of ETP. Energy Transfer Equity’s principal sources of distributable cash flow are its investments in the limited and general partner interests of ETP as follows:

§	Direct ownership of 62,500,797 ETP limited partner units representing approximately 46.0% of the total outstanding ETP units.

§	Indirect ownership of the 2% general partner interest of ETP and all associated IDRs held by ETP’s general partner, of which Energy Transfer Equity owns 100% of the membership interests. Currently, the quarterly general partner and associated IDR thresholds of ETP’s general partner are as follows:

§	2% of quarterly cash distributions up to $0.275 per unit paid by ETP;

§	15% of quarterly cash distributions from $0.275 per unit up to $0.3175 per unit paid by ETP;

§	25% of quarterly cash distributions from $0.3175 per unit up to $0.4125 per unit paid by ETP; and

§	50% of quarterly cash distributions that exceed $0.4125 per unit paid by ETP.

ETP’s partnership agreement requires that it distribute all of its Available Cash (as defined in such agreement) within 45 days following the end of each fiscal quarter.

ETP is a publicly traded partnership owning and operating a diversified portfolio of energy assets. ETP has pipeline operations in Arizona, Colorado, Louisiana, New Mexico and Utah, and owns the largest intrastate pipeline system in Texas. ETP’s natural gas operations include intrastate natural gas gathering and transportation pipelines, natural gas treating and processing assets and three natural gas storage facilities located in Texas. ETP is also one of the three largest retail marketers of propane in the United States, serving more than one million customers across the country.

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The balance sheet information and results of operations data for Energy Transfer Equity are summarized below.

	December 31,
	2008			2007
Balance Sheet Data:
Current assets	$	1,180,995		$	1,403,796
Property, plant and equipment, net		8,702,534			6,852,458
Other assets		1,186,373			1,205,840
Total assets	$	11,069,902		$	9,462,094
Current liabilities	$	1,208,921		$	1,241,433
Other liabilities		9,944,413			8,236,324
Partners’ equity		(83,432	)		(15,663	)
Total liabilities and partners’ equity	$	11,069,902		$	9,462,094

In November 2007, Energy Transfer Equity changed its fiscal year end to the calendar year end; thus, its current fiscal year began on January 1, 2008. Energy Transfer Equity completed a four-month transition period that began September 1, 2007 and ended December 31, 2007 and filed a transition report on Form 10-Q for that period in February 2008. Energy Transfer Equity subsequently filed audited financial statements for the four-month transition period on Form 8-K in March 2008.

Energy Transfer Equity did not recast its consolidated financial data for prior fiscal periods. According to Energy Transfer Equity, comparability between periods is impacted primarily by weather, fluctuations in commodity prices, volumes of natural gas sold and transported, its hedging strategies and use of financial instruments, trading activities, basis differences between market hubs and interest rates. Energy Transfer Equity believes that the trends indicated by comparison of the results for the calendar year ended December 31, 2008 are substantially similar to what is reflected in the information for the fiscal year ended August 31, 2007.

	For the Year		For the Four		For the Year
	Ended		Months Ended		Ended
	December 31,		December 31,		August 31,
	2008		2007		2007
Income Statement Data:
Revenues	$	9,293,367	$	2,349,342	$	6,792,037
Operating income		1,098,903		316,651		809,336
Net income		375,044		92,677		319,360

For the year ended December 31, 2008, Energy Transfer Equity received $546.2 million in cash distributions from ETP, which consisted of $236.3 million from limited partner interests, $17.9 million from its general partner interest and $305.1 million in distributions from the ETP IDRs. Energy Transfer Equity, in turn, paid $435.9 million in distributions to its partners with respect to the year ended December 31, 2008.

For the fiscal year ended August 31, 2007, Energy Transfer Equity received $370.7 million in cash distributions from ETP, which consisted of $175.0 million from limited partner interests, $12.7 million from its general partner interest and $183.0 million in distributions from the ETP IDRs. Energy Transfer Equity, in turn, paid $277.0 million in distributions to its partners with respect to the fiscal year ended August 31, 2007.

At December 31, 2008, the market value of the 38,976,090 common units of Energy Transfer Equity was approximately $631.8 million. We evaluated the near and long-term prospects of our investment in Energy Transfer Equity common units and concluded that this investment was not impaired at December 31, 2008. Our management believes that Energy Transfer Equity has significant growth prospects in the future that will enable the Parent Company to more than fully recover its investment. The Parent Company has the intent and ability to hold this investment for the long-term.

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Note 13. Business Combinations

The following table presents our cash used for business combinations by segment for the periods indicated:

	For Year Ended December 31,
	2008		2007		2006
Investment in Enterprise Products Partners:
Great Divide acquisition	$	125,175	$	--	$	--
South Monco acquisition		1		35,000		--
Encinal acquisition		--		114		145,197
Piceance Creek acquisition		--		368		100,000
Additional ownership interests in Dixie		57,089		--		12,913
Additional ownership interests in Tri-States and Belle Rose		19,895
Other business combinations		--		311		18,390
Subtotal		202,160		35,793		276,500
Investment in TEPPCO:
Marine Services Businesses purchased from Cenac		258,183		--		--
Marine Services Businesses purchased from Horizon		87,582		--		--
Terminal assets purchased from New York LP Gas
Storage, Inc.		--		--		9,931
Refined products terminal purchased from Mississippi
Terminal and Marketing Inc.		--		--		5,771
Other business combinations		5,561
Subtotal		351,326		--		15,702
Total	$	553,486	$	35,793	$	292,202

The following information highlights aspects of certain transactions noted in the preceding table:

Transactions Completed during the Year Ended December 31, 2008

Our expenditures for business combinations during the year ended December 31, 2008 were $553.5 million and primarily reflect the acquisitions described below.

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 2008, 2007 and 2006 due to the immaterial nature of our 2008 business combination transactions.

Great Divide Gathering System Acquisition. In December 2008, Enterprise Products Partners purchased a 100.0% membership interest in Great Divide Gathering, LLC (“Great Divide”) for cash consideration of $125.2 million. Great Divide was wholly owned by EnCana Oil & Gas (“EnCana”).

The assets of Great Divide consist of a 31-mile natural gas gathering system, the Great Divide Gathering System, located in the Piceance Basin of northwestern Colorado. The Great Divide Gathering System extends from the southern portion of the Piceance Basin, including production from EnCana’s Mamm Creek field, to a pipeline interconnection with Enterprise Products Partners’ Piceance Basin Gathering System. Volumes of natural gas originating on the Great Divide Gathering System are transported through Enterprise Products Partners’ Piceance Creek Gathering System to its 1.5 Bcf/d Meeker natural gas treating and processing complex. A significant portion of these volumes are produced by EnCana, one of the largest natural gas producers in the region, and are dedicated the Great Divide and Piceance Creek Gathering Systems for the life of the associated lease holdings.

Tri-States and Belle Rose Acquisitions. In October 2008, Enterprise Products Partners acquired additional 16.7% membership interests in both Tri-States NGL Pipeline, L.L.C. (“Tri-States”) and Belle Rose NGL Pipeline, L.L.C. (“Belle Rose”) for total cash consideration of $19.9 million. As a result of this

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transaction, Enterprise Products Partners’ ownership interest in Tri-States increased to 83.3%. Enterprise Products Partners now owns 100.0% of the membership interests in Belle Rose.

Tri-States owns a 194-mile NGL pipeline located along the Mississippi, Alabama and Louisiana Gulf Coast. Belle Rose owns a 48-mile NGL pipeline located in Louisiana. These systems, in conjunction with the Wilprise pipeline, transport mixed NGLs to the BRF, Norco and Promix NGL fractionators located in south Louisiana.

Acquisition of Remaining Interest in Dixie. In August 2008, Enterprise Products Partners acquired the remaining 25.8% ownership interest in Dixie for $57.1 million. As a result of this transaction, Enterprise Products Partners owns 100% of Dixie, which owns a 1,371-mile pipeline system that delivers NGLs (primarily propane, and other chemical feedstock) to customers along the U.S. Gulf Coast and southeastern United States.

TEPPCO Marine Services Businesses. On February 1, 2008, TEPPCO entered the marine transportation business for refined products, crude oil and condensate through the purchase of assets from Cenac Towing Co., Inc., Cenac Offshore, L.L.C., and Mr. Arlen B. Cenac, Jr. (collectively “Cenac”). The aggregate value of total consideration TEPPCO paid or issued to complete this business combination was $444.7 million, which consisted of $258.2 million in cash and approximately 4.9 million of TEPPCO’s newly issued common units. Additionally, TEPPCO assumed approximately $63.2 million of Cenac’s debt in the transaction. TEPPCO acquired 42 tow boats, 89 tank barges and the economic benefit of certain related commercial agreements. TEPPCO’s new business line serves refineries and storage terminals along the Mississippi, Illinois and Ohio rivers and the Intracoastal Waterway between Texas and Florida. These assets also gather crude oil from production facilities and platforms along the U.S. Gulf Coast and in the Gulf of Mexico. TEPPCO used its short-term credit facility to finance the cash portion of the acquisition. TEPPCO repaid the $63.2 million of debt assumed in this transaction using borrowings under its short-term credit facility.

On February 29, 2008, TEPPCO purchased related marine assets from Horizon Maritime, L.L.C. (“Horizon”), a privately-held Houston-based company and an affiliate of Mr. Cenac, for $80.8 million in cash. TEPPCO acquired 7 tow boats, 17 tank barges, rights to two tow boats under construction and the economic benefit of certain related commercial agreements. In April 2008, TEPPCO paid an additional $3.0 million to Horizon pursuant to the purchase agreement upon delivery of one of the tow boats under construction, and in June 2008, TEPPCO paid an additional $3.8 million upon delivery of the second tow boat. These vessels transport asphalt, heavy fuel oil and other heated oil products to storage facilities and refineries along the Mississippi, Illinois and Ohio Rivers and the Intracoastal Waterway. TEPPCO’s short-term credit facility was used to finance this acquisition.

The results of operations related to these assets are included in our Condensed Statements of Consolidated Operations beginning at the date of acquisition.

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Purchase Price Allocations. We accounted for our business combinations completed during 2008 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.

	Cenac			Horizon		Great
	Acquisition			Acquisition		Divide			Dixie			Other (1)			Total
Assets acquired in business combination:
Current assets	$	--		$	--	$	--		$	4,021		$	2,510		$	6,531
Property, plant and equipment, net		362,872			72,196		70,643			33,727			10,122			549,560
Intangible assets		63,500			6,500		9,760			--			12,747			92,507
Other assets		--			--		--			382			46			428
Total assets acquired		426,372			78,696		80,403			38,130			25,425			649,026
Liabilities assumed in business combination:
Current liabilities		--			--		--			(2,581	)		(649	)		(3,230	)
Long-term debt		--			--		--			(2,582	)		--			(2,582	)
Other long-term liabilities		(63,157	)		--		(81	)		(46,265	)		(4	)		(109,507	)
Total liabilities assumed		(63,157	)		--		(81	)		(51,428	)		(653	)		(115,319	)
Total assets acquired plus liabilities assumed		363,215			78,696		80,322			(13,298	)		24,772			533,707
Fair value of 4,854,899 TEPPCO common units		186,558			--		--			--			--			186,558
Total cash used for business combinations		258,183			87,582		125,175			57,089			25,457			553,486
Goodwill	$	81,526		$	8,886	$	44,853		$	70,387		$	685		$	206,337

(1) Primarily represents (i) non-cash reclassification adjustments to Enterprise Products Partners’ December 2007 preliminary fair value estimates for assets acquired in its South Monoco natural gas pipeline acquisition, (ii) TEPPCO’s purchase of lubrication and other fuel assets in August 2008 and (iii) Enterprise Products’ purchase of additional interests in Tri-States and Belle Rose in October 2008.

As a result of Enterprise Products Partners’ 100% ownership interest in Dixie, Enterprise Products Partners used push-down accounting to record this business combination. In doing so, a temporary tax difference was created between the assets and liabilities of Dixie for financial reporting and tax purposes. Dixie recorded a deferred income tax liability of $45.1 million attributable to the temporary tax difference.

Transactions Completed during the Year Ended December 31, 2007

Our expenditures for business combinations during the year ended December 31, 2007 were $35.8 million, which primarily reflect the $35.0 million Enterprise Products Partners spent to acquire 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.

Transactions Completed during the Year Ended December 31, 2006

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 common units of Enterprise Products Partners.

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.

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The Encinal and Canales gathering systems are 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. The Big Reef 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.

In accordance with purchase accounting, the value of Enterprise Products Partners’ 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.

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 year ended December 31, 2006 as if the Encinal acquisition had been completed on January 1, 2006 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, 2006.

The amounts shown in the following table are in millions, except per unit amounts.

	For the
	Year Ended
	December 31, 2006
Pro forma earnings data:
Revenues	$	23,685.9
Costs and expenses	$	22,595.6
Operating income	$	1,115.6
Net income	$	99.9
Basic earnings per unit ("EPU"):
Units outstanding, as reported		103.1
Units outstanding, pro forma		103.1
Basic EPU, as reported	$	1.30
Basic EPU, pro forma	$	0.97
Diluted EPU:
Units outstanding, as reported		103.1
Units outstanding , pro forma		103.1
Diluted EPU, as reported	$	1.30
Diluted EPU, pro forma	$	0.97

Piceance Creek Acquisition. In December 2006, Enterprise Products Partners purchased a 100% interest in Piceance Creek Pipeline, LLC (“Piceance Creek”), for $100.0 million. Piceance Creek was wholly owned by EnCana.

The assets of Piceance Creek consisted 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 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 (see above for Enterprise Products Partners’ purchase of this system in 2008) 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

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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.

Note 14. Intangible Assets and Goodwill

Identifiable Intangible Assets

The following tables summarize our intangible assets at the dates indicated:

	December 31, 2008
	Gross		Accum.			Carrying
	Value		Amort.			Value
Investment in Enterprise Products Partners:
Customer relationship intangibles	$	858,354	$	(272,918	)	$	585,436
Contract-based intangibles		409,283		(156,603	)		252,680
Subtotal		1,267,637		(429,521	)		838,116
Investment in TEPPCO:
Incentive distribution rights		606,926		--			606,926
Customer relationship intangibles		52,381		(3,506	)		48,875
Gas gathering agreements		462,449		(212,610	)		249,839
Other contract-based intangibles		74,515		(29,224	)		45,291
Subtotal		1,196,271		(245,340	)		950,931
Total	$	2,463,908	$	(674,861	)	$	1,789,047

	December 31, 2007
	Gross		Accum.			Carrying
	Value		Amort.			Value
Investment in Enterprise Products Partners:
Customer relationship intangibles	$	845,607	$	(213,215	)	$	632,392
Contract-based intangibles		395,235		(128,209	)		267,026
Subtotal		1,240,842		(341,424	)		899,418
Investment in TEPPCO:
Incentive distribution rights		606,926		--			606,926
Customer relationship intangibles		501		(111	)		390
Gas gathering agreements		462,449		(181,372	)		281,077
Other contract-based intangibles		55,126		(22,738	)		32,388
Subtotal		1,125,002		(204,221	)		920,781
Total	$	2,365,844	$	(545,645	)	$	1,820,199

The following table presents the amortization expense of our intangible assets by segment for the periods indicated:

	For Year Ended December 31,
	2008		2007		2006
Investment in Enterprise Products Partners	$	88,097	$	89,727	$	88,755
Investment in TEPPCO		41,793		35,584		33,269
Total	$	129,890	$	125,311	$	122,024

We estimate that amortization expense associated with our portfolio of intangible assets at December 31, 2008 will approximate $122.0 million for 2009, $115.9 million for 2010, $108.1 million for 2011, $93.1 million for 2012 and $85.4 million for 2013.

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In general, our amortizable intangible assets fall within two categories – contract-based intangible assets and customer relationships. The values assigned to such 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.

Customer relationship intangible assets. Customer relationship intangible assets represent the estimated economic value assigned to certain relationships acquired in connection with business combinations and asset purchases whereby (i) we acquired information about or access to customers and now have regular contact with them and (ii) the customers now have the ability to make direct contact with us. Customer relationships may arise from contractual arrangements (such as supplier contracts and service contracts) and through means other than contracts, such as through regular contact by sales or service representatives.

At December 31, 2008, the carrying value of Enterprise Products Partners’ customer relationship intangible assets was $585.4 million. The carrying value of TEPPCO’s customer relationship intangible assets was $48.9 million. The following information summarizes the significant components of this category of intangible assets:

San Juan Gathering System customer relationships – Enterprise Products Partners acquired these customer relationships in connection with the GulfTerra Merger, which was completed on September 30, 2004. At December 31, 2008, the carrying value of this group of intangible assets was $238.8 million. These intangible assets are being amortized to earnings over their estimated economic life of 35 years through 2039. Amortization expense is recorded using a method that closely resembles the pattern in which the economic benefits of the underlying natural gas resource bases are expected to be consumed or otherwise used.

Offshore Pipeline & Platform customer relationships – Enterprise Products Partners acquired these customer relationships in connection with the GulfTerra Merger. At December 31, 2008, the carrying value of this group of intangible assets was $115.2 million. These intangible assets are being amortized to earnings over their estimated economic life of 33 years through 2037. Amortization expense is recorded using a method that closely resembles the pattern in which the economic benefits of the underlying crude oil and natural gas resource bases are expected to be consumed or otherwise used.

Encinal natural gas processing customer relationship – Enterprise Products Partners acquired this customer relationship in connection with its Encinal acquisition in 2006. At December 31, 2008, the carrying value of this intangible asset was $99.1 million. This intangible asset is being amortized to earnings over its estimated economic life of 20 years through 2026. Amortization expense is recorded using a method that closely resembles the pattern in which the economic benefit of the underlying natural gas resource bases are expected to be consumed or otherwise used.

Contract-based intangible assets. Contract-based intangible assets represent specific commercial rights we acquired in connection with business combinations or asset purchases. At December 31, 2008, the carrying value of Enterprise Products Partners’ contract-based intangible assets was $252.7 million. The carrying value of TEPPCO’s contract-based intangible assets was $295.1 million. The following information summarizes the significant components of this category of intangible assets:

Jonah natural gas gathering agreements – These intangible assets represent the value attributed to certain of Jonah’s natural gas gathering contracts that existed at February 24, 2005, which was the date that private company affiliates of EPCO first acquired their ownership interests in TEPPCO and TEPPCO GP. At December 31, 2008, the carrying value of this group of intangible assets was $136.0 million. These intangible assets are being amortized to earnings using a units-of-production method based on throughput volumes on the Jonah system.

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Val Verde natural gas gathering agreements – These intangible assets represent the value attributed to certain natural gas gathering agreements associated with TEPPCO’s Val Verde Gathering System that existed at February 24, 2005, which was the date that private company affiliates of EPCO first acquired their ownership interests in TEPPCO and TEPPCO GP. At December 31, 2008, the carrying value of these intangible assets was $113.8 million. These intangible assets are being amortized to earnings using a units-of-production method based on throughput volumes on the Val Verde Gathering System.

Shell Processing Agreement – This margin-band/keepwhole processing agreement grants Enterprise Products Partners the right to process Shell Oil Company’s (or its assignee’s) current and future natural gas production of within the state and federal waters of the Gulf of Mexico. Enterprise Products Partners acquired the Shell Processing Agreement in connection with its 1999 purchase of certain of Shell’s midstream energy assets located along the U.S. Gulf Coast. At December 31, 2008, the carrying value of this intangible asset was $116.9 million. This intangible asset is being amortized to earnings on a straight-line basis over its estimated economic life of 20 years through 2019.

Mississippi natural gas storage contracts – These intangible assets represent the value assigned by Enterprise Products Partners to certain natural gas storage contracts associated with its Petal and Hattiesburg, Mississippi storage facilities. These facilities were acquired in connection with the GulfTerra Merger. At December 31, 2008, the carrying value of these intangible assets was $64.0 million. These intangible assets are being amortized to earnings on a straight-line basis over the remainder of their respective contract terms, which range from eight to 18 years (i.e. 2012 through 2022).

Incentive distribution rights. The Parent Company recorded an indefinite-life intangible asset valued at $606.9 million in connection with the receipt of the TEPPCO IDRs from DFIGP in May 2007. This amount represents DFIGP’s historical carrying value and characterization of such asset. This intangible asset is not subject to amortization, but it subject to periodic testing for recoverability in a manner similar to goodwill.

The IDRs represent contractual rights to the incentive cash distributions paid by TEPPCO. Such rights were granted to TEPPCO GP under the terms of TEPPCO’s partnership agreement. In accordance with TEPPCO’s partnership agreement, TEPPCO GP may separate and sell the IDRs independent of its other residual general partner and limited partner interests in TEPPCO. TEPPCO GP is entitled to 2% of the cash distributions paid by TEPPCO as well as the associated IDRs of TEPPCO. TEPPCO GP is the sole general partner of, and thereby controls, TEPPCO. As an incentive, TEPPCO GP’s percentage interest in TEPPCO’s quarterly cash distributions is increased after certain specified target levels of distribution rates are met by TEPPCO. See Note 24 for additional information regarding TEPPCO GP’s quarterly incentive distribution thresholds.

We consider the IDRs to be an indefinite-life intangible asset. Our determination of an indefinite-life is based upon our expectation that TEPPCO will continue to pay incentive distributions under the terms of its partnership agreement to TEPPCO GP indefinitely. TEPPCO’s partnership agreement contains renewal provisions that provide for TEPPCO to continue as a going concern beyond the initial term of its partnership agreement, which ends in December 2084.

We test the carrying value of the IDRs for impairment annually, or more frequently if circumstances indicate that it is more likely than not that the fair value of the asset is less than its carrying value. This test is performed during the fourth quarter of each fiscal year. If the estimated fair value of this intangible asset is less its carrying value, a charge to earnings is required to reduce the asset’s carrying value to its implied fair value. In addition, we review this asset annually to determine whether events or circumstances continue to support an indefinite life.

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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. No goodwill impairment losses were recorded during the years ended December 31, 2008, 2007 or 2006. The following table summarizes our goodwill amounts by business segment at the dates indicated:

	December 31,
	2008		2007
Investment in Enterprise Products Partners:
GulfTerra Merger	$	385,945	$	385,945
Encinal acquisition		95,272		95,280
Acquisition of additional interests in Dixie		80,279		9,892
Great Divide acquisition		44,853		--
Other		100,535		100,535
Investment in TEPPCO:
TEPPCO acquisition		197,645		197,645
Marine services acquisition		90,412		--
Other		18,976		18,283
Total	$	1,013,917	$	807,580

In 2008, our Investment in Enterprise Products Partners business segment recorded goodwill of $70.4 million in connection with the acquisition of the remaining third party interest in Dixie and $44.9 million in connection with the acquisition of Great Divide. The remaining ownership interests in Dixie were acquired from Amoco Pipeline Holding Company in August 2008. Management attributes this goodwill to future earnings growth on the Dixie Pipeline. Specifically, a 100.0% ownership interest in the Dixie Pipeline will increase Enterprise Products Partners’ flexibility to pursue future opportunities.

Great Divide was acquired from EnCana in December 2008. Goodwill for this acquisition is attributable to management’s expectations of future benefits derived from incremental natural gas processing margins and other downstream activities. For additional information regarding these acquisitions see Note 12.

In addition, our Investment in Enterprise Products Partners business segment includes goodwill amounts recorded in connection with the GulfTerra Merger. The value associated with such goodwill amounts can be attributed to our belief (at the time the merger was consummated) that the combined partnerships would benefit from the strategic asset locations and industry relationships that each partnership 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.

Management attributes goodwill amounts recorded in connection with the Encinal acquisition to potential future benefits Enterprise Products Partners may realize from its other south Texas natural gas processing and NGL businesses. Specifically, Enterprise Products Partners’ acquisition of long-term dedication rights associated with the Encinal business is expected to add value to its south Texas processing facilities and related NGL businesses due to increased volumes.

In 2008, our Investment in TEPPCO business segment recorded goodwill of $90.4 million in connection with its marine services acquisitions. Management attributes the value of this goodwill to potential future benefits TEPPCO expects to realize as a result of acquiring these assets. For additional information regarding this acquisitions see Note 12.

In addition, our Investment in TEPPCO business segment includes goodwill amounts recorded in connection with DFIGP’s contribution of ownership interests in TEPPCO and TEPPCO GP to the Parent

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Company on May 7, 2007. At December 31, 2008 and 2007, the TEPPCO business segment included $197.6 million of such goodwill amounts.

Goodwill associated with DFIGP’s contribution of ownership interests in TEPPCO and TEPPCO GP to the Parent Company represents DFIGP’s historical carrying value and characterization of such asset. Management attributes this goodwill to the future benefits we may realize from our investments in TEPPCO and TEPPCO GP. Specifically, we will benefit from the cash distributions paid by TEPPCO with respect to TEPPCO GP’s 2% general partner interest in TEPPCO and ownership of 4,400,000 of its common units.

Note 15. Debt Obligations

The following table summarizes the significant components of our consolidated debt obligations at the dates indicated:

	December 31,
	2008			2007
Principal amount of debt obligations of the Parent Company	$	1,077,000		$	1,090,000
Principal amount of debt obligations of Enterprise Products Partners:
Senior debt obligations		7,813,346			5,646,500
Subordinated debt obligations		1,232,700			1,250,000
Total principal amount of debt obligations of Enterprise Products Partners		9,046,046			6,896,500
Principal amount of debt obligations of TEPPCO:
Senior debt obligations		2,216,653			1,545,000
Subordinated debt obligations		300,000			300,000
Total principal amount of debt obligations of TEPPCO		2,516,653			1,845,000
Total principal amount of consolidated debt obligations		12,639,699			9,831,500
Other, non-principal amounts:
Changes in fair value of debt-related financial instruments (see Note 8)		51,935			14,839
Unamortized discounts, net of premiums		(12,549	)		(7,297	)
Unamortized deferred gains related to terminated interest rate swaps (see Note 8)		35,843			22,163
Total other, non-principal amounts		75,229			29,705
Total long-term debt		12,714,928			9,861,205
Less current maturities of TEPPCO long-term debt		--			(353,976	)
Total consolidated debt obligations	$	12,714,928		$	9,507,229

Standby letters of credit outstanding:
Enterprise Products Partners	$	1,000		$	1,100
TEPPCO		--			23,494
Total standby letters of credit	$	1,000		$	24,594

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Debt Obligations of the Parent Company

The Parent Company consolidates the debt obligations of both Enterprise Products Partners and TEPPCO; however, the Parent Company does not have the obligation to make interest or debt payments with respect to the consolidated debt obligations of either Enterprise Product Partners or TEPPCO.

The following table summarizes the debt obligations of the Parent Company at the dates indicated:

	December 31,
	2008		2007
EPE Revolver, variable rate, due September 2012	$	102,000	$	115,000
$125.0 million Term Loan A, variable rate, due September 2012		125,000		125,000
$850.0 million Term Loan B, variable rate, due November 2014 (1)		850,000		850,000
Total debt obligations of the Parent Company	$	1,077,000	$	1,090,000

(1) 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, 2008. With respect to the $17.0 million due under Term Loan B in 2009, the Parent Company has the ability to use available credit capacity under its revolving credit facility to fund repayment of these amounts.

EPE $200.0 Million Credit Facility. In January 2006, the Parent Company amended and restated its original $525.0 million credit facility to reflect a new borrowing capacity of $200.0 million, which included a sublimit of $25.0 million for letters of credit. Amounts borrowed under the $200.0 million credit facility (the “EPE Revolver”) were due in January 2009. The Parent Company secured borrowings under this credit facility with a pledge of its limited and general partner ownership interests in Enterprise Products Partners. This facility was amended and restated in May 2007 as the EPE Interim Credit Facility.

EPE Interim Credit Facility. In May 2007, the Parent Company executed a $1.9 billion interim credit facility (the “EPE Interim Credit Facility”) in connection with its acquisition of equity interests in Energy Transfer Equity and LE GP. The EPE Interim Credit Facility, which amended and restated the terms of its then existing credit facility (the “EPE $200.0 Million Credit Facility”), provided for a $200.0 million revolving credit facility (the “EPE Bridge Revolving Credit Facility”) and $1.7 billion of term loans. The term loans were segregated into two tranches: a $500.0 million EPE Term Loan (Equity Bridge) and a $1.2 billion EPE Term Loan (Debt Bridge).

On May 7, 2007, the Parent Company made initial borrowings of $1.8 billion under this credit facility as follows:

§	$155.0 million to repay principal outstanding under the EPE $200.0 Million Credit Facility; and

§	$1.2 billion under the EPE Term Loan (Debt Bridge) and $500.0 million under the EPE Term Loan (Equity Bridge) to fund the $1.65 billion cash purchase price for the acquisition of membership interests in LE GP and common units of Energy Transfer Equity.

In July 2007, the Parent Company used net proceeds from its private placement of Units (see Note 16) to repay the $500.0 million in principal outstanding under the EPE Term Loan (Equity Bridge), $238.0 million to reduce principal outstanding under the EPE Term Loan (Debt Bridge) and $2.0 million of related accrued interest. The remaining balances due under the EPE Bridge Revolving Credit Facility and EPE Term Loan (Debt Bridge) were to mature in May 2008.

In August 2007, the Parent Company refinanced the $1.2 billion then outstanding under the EPE Interim Credit Facility using proceeds from its EPE August 2007 Credit Agreement.

EPE August 2007 Credit Agreement. The $1.2 billion EPE August 2007 Credit Agreement provided for a $200.0 million revolving credit facility (the “EPE Revolver”), a $125.0 million term loan (“Term Loan A”), and an $850.0 million term loan (the “Term Loan A-2”). The EPE Revolver replaced the $200.0 million EPE Bridge Revolving Credit Facility. Amounts borrowed under the August 2007

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Revolver mature in September 2012. Term Loan A and Term Loan A-2 refinanced amounts then outstanding under the Term Loan (Debt Bridge). Amounts borrowed under Term Loan A mature in September 2012. Amounts borrowed under Term Loan A-2 were refinanced in November 2007 with proceeds from a term loan due November 2014.

Borrowings under the EPE August 2007 Credit Agreement are secured by the Parent Company’s ownership of (i) 13,454,498 common units of Enterprise Products Partners, (ii) 100% of the membership interests in EPGP, (iii) 38,976,090 common units of Energy Transfer Equity, (iv) 4,400,000 common units of TEPPCO and (v) 100% of the membership interests in TEPPCO GP.

The EPE Revolver may be used by the Parent Company to fund working capital and other capital requirements and for general partnership purposes. The EPE 2007 Revolver offers secured ABR loans (“ABR Loans”) and Eurodollar loans (“Eurodollar Loans”) each having different interest requirements.

ABR Loans bear interest at an alternative base rate (the “Alternative Base Rate”) plus an applicable rate (the “Applicable Rate”). The Alternative Base Rate is a rate per annum equal to the greater of: (i) the annual interest rate publicly announced by Citibank, N.A. as its base rate in effect at its principal office in New York, New York (the “Prime Rate”) in effect on such day and (ii) the federal funds effective rate in effect on such day plus 0.50%. The Applicable Rate for ABR Loans will be increased by an applicable margin ranging from 0% to 1.0% per annum. The Eurodollar Loans bear interest at a “LIBOR rate” (as defined in the August 2007 Credit Agreement) plus the Applicable Rate. The Applicable Rate for Eurodollar Loans will be increased by an applicable margin ranging from 1.00% to 2.50% per annum.

All borrowings outstanding under Term Loan A will, at the Parent Company’s option, be made and maintained as ABR Loans or Eurodollar Loans, or a combination thereof. Prior to being refinanced in November 2007, borrowings outstanding under Term Loan A-2 were charged interest at the LIBOR rate plus 1.75%. Any amount repaid under the Term Loan A may not be reborrowed.

In November 2007, the Parent Company executed a seven-year, $850 million senior secured term loan (“Term Loan B”) in the institutional leveraged loan market. Proceeds from the Term Loan B were used to permanently refinance borrowings outstanding under the partnership’s $850 million Term Loan A-2 that had a maturity date in May 2008. The Term Loan B, which was priced at a discount of 1.0 percent, generally bears interest at LIBOR plus 2.25 percent and is scheduled to mature on November 8, 2014. The Term Loan B is callable for up to one year by the partnership at 101 percent of the principal, and at par thereafter.

The EPE August 2007 Credit Agreement contains various covenants related to the Parent Company’s ability to incur certain indebtedness, grant certain liens, make fundamental structural changes, make distributions following an event of default and enter into certain restricted agreements. The credit agreement also requires the Parent Company to satisfy certain quarterly financial covenants.

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Consolidated Debt Obligations of Enterprise Products Partners

The following table summarizes the principal amount of consolidated debt obligations of Enterprise Products Partners at the dates indicated:

	December 31,
	2008		2007
Senior debt obligations of Enterprise Products Partners:
EPO Revolver, variable rate, due November 2012	$	800,000	$	725,000
EPO Senior Notes B, 7.50% fixed-rate, due February 2011		450,000		450,000
EPO Senior Notes C, 6.375% fixed-rate, due February 2013		350,000		350,000
EPO Senior Notes D, 6.875% fixed-rate, due March 2033		500,000		500,000
EPO Senior Notes F, 4.625% fixed-rate, due October 2009 (1)		500,000		500,000
EPO Senior Notes G, 5.60% fixed-rate, due October 2014		650,000		650,000
EPO Senior Notes H, 6.65% fixed-rate, due October 2034		350,000		350,000
EPO Senior Notes I, 5.00% fixed-rate, due March 2015		250,000		250,000
EPO Senior Notes J, 5.75% fixed-rate, due March 2035		250,000		250,000
EPO Senior Notes K, 4.950% fixed-rate, due June 2010		500,000		500,000
EPO Senior Notes L, 6.30%, fixed-rate, due September 2017		800,000		800,000
EPO Senior Notes M, 5.65%, fixed-rate, due April 2013		400,000		--
EPO Senior Notes N, 6.50%, fixed-rate, due January 2019		700,000		--
EPO Senior Notes O, 9.75% fixed-rate, due January 2014		500,000		--
EPO Yen Term Loan, 4.93% fixed-rate, due March 2009 (1)		217,596		--
Petal GO Zone Bonds, variable rate, due August 2037		57,500		57,500
Pascagoula MBFC Loan, 8.70% fixed-rate, due March 2010		54,000		54,000
Dixie Revolver, variable rate, due June 2010 (2)		--		10,000
Duncan Energy Partners’ Revolver, variable rate, due February 2011		202,000		200,000
Duncan Energy Partners’ Term Loan Agreement, variable rate, due December 2011		282,250		--
Total senior debt obligations of Enterprise Products Partners		7,813,346		5,646,500
Subordinated debt obligations of Enterprise Products Partners:
EPO Junior Notes A, fixed/variable rates, due August 2066		550,000		550,000
EPO Junior Notes B, fixed/variable rates, due January 2068		682,700		700,000
Total subordinated debt obligations of Enterprise Products Partners		1,232,700		1,250,000
Total principal amount of debt obligations of Enterprise Products Partners	$	9,046,046	$	6,896,500

(1) 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, 2008. With respect to the EPO Yen Term Loan due March 2009 and EPO Senior Notes F due October 2009, EPO has the ability to use available credit capacity under the EPO Revolver to fund repayment of these amounts. (2) The Dixie Revolver was terminated in January 2009.

Enterprise Products Partners L.P. acts as guarantor of the consolidated debt obligations of EPO with the exception of Duncan Energy Partners’ revolving credit facility and Term Loan Agreement. If EPO were to default on any of its guaranteed debt, Enterprise Products Partners L.P. would be responsible for full repayment of that obligation. EPO’s debt obligations are non-recourse to the Parent Company and EPGP.

Letters of credit. At December 31, 2008 and 2007, there was $1.0 million and $1.1 million, respectively, in standby letters outstanding under Duncan Energy Partners’ Revolver.

EPO Revolver. This unsecured revolving credit facility currently has a borrowing capacity of $1.75 billion, which replaced an existing $1.25 billion unsecured revolving credit agreement. Amounts borrowed under the amended and restated credit agreement mature in November 2012, although EPO is permitted, on the maturity date, 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 limit on the amount of standby letters of credit that can be outstanding under the amended facility.

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.

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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 revolving credit agreement 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 Enterprise Products Partners 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.

EPO 364-Day Revolving Credit Facility. In November 2008, EPO executed a 364-Day Revolving Credit Agreement (“EPO 364-Day Revolving Credit Facility”) in the amount of $375.0 million. EPO’s obligations under its 364-Day Revolving Credit Facility are not secured by any collateral; however, the obligations are guaranteed by Enterprise Products Partners L.P. pursuant to a guaranty agreement. The EPO 364-Day Revolving Credit Facility will mature on November 16, 2009. As of December 31, 2008, there were no borrowings outstanding under this credit facility.

The EPO 364-Day Revolving Credit Facility offers the following loans, each having different interest requirements: (i) LIBOR loans bear interest at a rate per annum equal to LIBOR plus the applicable LIBOR margin and (ii) Base Rate loans bear interest each day at a rate per annum equal to the higher of (a) the rate of interest announced by the administrative agent as its prime rate, (b) 0.5% per annum above the Federal Funds Rate in effect on such date , and (c) 1.0% per annum above LIBOR in effect on such date plus, in each case, the applicable Base Rate margin.

The commitments may be increased by an amount not to exceed $1.0 billion by adding one or more new lenders to the facility or increasing the commitments of existing lenders, although none of the existing lenders has agreed to or is obligated to increase its existing commitment. With certain exceptions and after certain time periods, if EPO issues debt with a maturity of more than three years, the lenders’ commitments under the EPO 364-Day Revolving Credit Facility will be reduced to the extent of any debt proceeds, and any outstanding loans in excess of such reduced commitments must be repaid.

EPO 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. Enterprise Products Partners has guaranteed repayment of amounts due under these notes through an unsecured and unsubordinated guarantee. 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 revolving credit facility and for general partnership purposes. In October 2007, EPO used borrowing capacity under its revolving credit facility to repay its $500.0 million Senior Notes E.

EPO Senior Notes M and N. In April 2008, EPO issued $400.0 million in principal amount of 5-year senior unsecured notes (“EPO Senior Notes M”) and $700.0 million in principal amount of 10-year senior unsecured notes (“EPO Senior Notes N”) under its universal registration statement. Senior Notes M were issued at 99.906% of their principal amount, have a fixed interest rate of 5.65% and mature in April 2013. Senior Notes N were issued at 99.866% of their principal amount, have a fixed interest rate of 6.50% and mature in January 2019.

EPO Senior Notes M pay interest semi-annually in arrears on April 1 and October 1 of each year. EPO Senior Notes N pay interest semi-annually in arrears on January 31 and July 31 of each year. Net

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proceeds from the issuance of EPO Senior Notes M and N were used to temporarily reduce indebtedness outstanding under the EPO Revolver.

EPO Senior Notes M and N rank equal with EPO’s existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. EPO Senior Notes M and N 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 Senior Notes O. In December 2008, EPO issued $500.0 million in principal amount of 5-year senior unsecured notes (“EPO Senior Notes O”) under its universal registration statement. EPO Senior Notes O were issued at 100.0% of their principal amount, have a fixed interest rate of 9.75% and mature in January 2014.

EPO Senior Notes O pay interest semi-annually in arrears on January 31 and July 31 of each year, commencing January 31, 2009. Net proceeds from the issuance of EPO Senior Notes O were used to temporarily reduce indebtedness outstanding under the EPO Revolver.

EPO Senior Notes O rank equal with EPO’s existing and future unsecured and unsubordinated indebtedness. They are senior to any existing and future subordinated indebtedness of EPO. EPO Senior Notes O 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 Japanese Yen Term Loan. In November 2008, EPO executed the Yen Term Loan in the amount of approximately 20.7 billion yen (approximately $217.6 million U.S. Dollar equivalent on the closing date). EPO’s obligations under the Yen Term Loan are not secured by any collateral; however, the obligations are guaranteed by Enterprise Products Partners L.P. pursuant to a guaranty agreement. The Yen Term Loan will mature on March 30, 2009.

Under the Yen Term Loan, interest accrues on the loan at the Tokyo Interbank Offered Rate (“TIBOR”) plus 2.0%. EPO entered into foreign exchange currency swaps that effectively convert the TIBOR loan into a U.S. Dollar loan with a fixed interest rate (including the cost of the swaps) through maturity of approximately 4.93%. As a result, EPO received US$217.6 million net from this transaction. In addition, EPO executed a forward purchase exchange (yen principal and interest due) for March 30, 2009 at an exchange rate of 94.515 to eliminate foreign exchange risk, resulting in a payment of US$221.6 million on March 30, 2009. See Note 8 for additional information regarding this forward purchase exchange.

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, 2008, 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 Sheets. The interest income and expenses are netted in preparing our Statements of Consolidated Operations.

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 under the EPO Revolver. On the same date, the MBFC issued $57.5 million in Gulf Opportunity Zone Tax-Exempt (“GO Zone”) bonds to various third

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parties. A portion of the GO Zone bond proceeds were being held by a third party trustee and reflected as a component of other assets on our balance sheet. During 2008, virtually all proceeds from the GO Zone bonds were released by the trustee to fund construction costs associated with the expansion of Enterprise Products Partners’ Petal, Mississippi storage facility. 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 30 years. The bonds and the associated tax incentives are authorized under the Mississippi Business Finance Act and the Gulf Opportunity Zone Act of 2005.

Pascagoula MBFC Loan. In connection with the construction of a natural gas processing plant located in Mississippi 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. The Pascagoula MBFC Loan contains certain covenants including the maintenance of appropriate levels of insurance on the processing plant.

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 Enterprise Products Partners’ 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 our obligation under this loan.

Dixie Revolver. Dixie’s debt obligation consisted of a senior, unsecured revolving credit facility having a borrowing capacity of $28.0 million. As of December 31, 2008, there were no debt obligations outstanding under the Dixie Revolver. This credit facility was terminated in January 2009. EPO consolidated the debt of Dixie.

Variable interest rates charged under this facility generally bore interest, at Dixie’s 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 Effective Rate plus 0.5%.

Duncan Energy Partners’ Revolver. In February 2007, 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 (as defined in the credit agreement). Letters of credit outstanding under this credit facility reduce the amount available for borrowing. The $300.0 million borrowing capacity under this agreement may be increased to $450.0 million under certain conditions. The maturity date of this credit facility is February 2011; however, Duncan Energy Partners may request up to two one-year extensions of the maturity date (subject to certain conditions).

EPO consolidates the debt of Duncan Energy Partners; however, EPO does not have the obligation to make interest or debt payments with respect to Duncan Energy Partners’ debt. At the closing of its initial public offering in February 2007, Duncan Energy Partners borrowed $200.0 million under this credit facility to fund a $198.9 million cash distribution to EPO and the remainder to pay debt issuance costs.

Variable interest rates charged under this facility generally bear interest, at Duncan Energy Partners’ election at the time of each borrowing, at either (i) a Eurodollar rate, plus an applicable margin (as defined in the credit agreement) or (ii) the greater of (a) the lender’s base rate as defined in the agreement or (b) the Federal Funds Effective Rate plus 0.5%.

The revolving credit agreement contains various covenants related to Duncan Energy Partners’ ability to, among other things, incur certain indebtedness; grant certain liens; enter into certain merger or consolidation transactions; and make certain investments. In addition, the revolving credit agreement restricts Duncan Energy Partners’ ability to pay cash distributions to EPO and its public unitholders if a default or an event of default (as defined in the credit agreement) has occurred and is continuing at the time

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such distribution is scheduled to be paid. Duncan Energy Partners must also satisfy certain financial covenants at the end of each fiscal quarter.

Duncan Energy Partners’ Term Loan Agreement. In April 2008, Duncan Energy Partners entered into a standby term loan agreement with certain lenders consisting of commitments for up to a $300.0 million senior unsecured term loan (the “Duncan Energy Partners’ Term Loan Agreement”). Subsequently, commitments under this agreement decreased to $282.3 million due to bankruptcy of one of the lenders. In December 2008, Duncan Energy Partners borrowed the full amount available under this loan agreement to fund cash consideration due Enterprise Products Partners in connection with an asset dropdown transaction.

Loans under the term loan agreement are due and payable on December 8, 2011. Duncan Energy Partners may also prepay loans under the term loan agreement at any time, subject to prior notice in accordance with the credit agreement. Loans may also be payable earlier in connection with an event of default.

Loans under the term loan agreement bear interest of the type specified in the applicable borrowing request, and consist of either Alternate Base Rate (“ABR”) loans or Eurodollar loans. The term loan agreement contains customary affirmative and negative covenants.

EPO Junior Notes A. In the third quarter of 2006, EPO issued $550.0 million in principal amount of fixed/floating subordinated notes due August 2066 (“EPO Junior Notes A”). Proceeds from this debt offering were used to temporarily reduce borrowings outstanding under the EPO Revolver and for general partnership purposes. These notes are unsecured obligations of EPO and are subordinated to its existing and future unsubordinated indebtedness. EPO’s payment obligations under the Junior Notes are subordinated to all of its current and future senior indebtedness (as defined in the related indenture agreement).

The indenture agreement governing the Junior Notes 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 the Junior Notes has been paid in full as of the most recent applicable interest payment dates, (ii) no event of default under the indenture agreement has occurred and is continuing and (iii) Enterprise Products Partners is not in default of its obligations under related guarantee agreements, neither Enterprise Products Partners nor EPO may declare or make any distributions to any of their respective equity security holders or make any payments on indebtedness or other obligations that rank pari passu with or are subordinated to the Junior Notes .

In connection with the issuance of EPO 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 issuance of certain securities.

The EPO Junior Notes A bear interest at a fixed annual rate of 8.375% from July 2006 to August 2016, payable semi-annually in commencing in February 2007. After August 2016, the notes will bear variable rate interest based on the 3-month LIBOR for the related interest period plus 3.708%, payable quarterly 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 EPO Junior Notes A mature in August 2066 and are not redeemable by EPO prior to August 2016 without payment of a make-whole premium.

EPO Junior Notes B. EPO issued $700.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due January 2068 (“EPO Junior Notes B”) during the second quarter of 2007. EPO used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Revolver and for general partnership purposes. EPO’s payment obligations under EPO Junior Notes B are subordinated to all of its current and future senior indebtedness (as defined in the Indenture Agreement). Enterprise Products Partners has guaranteed repayment of amounts due under EPO Junior Notes B through an unsecured and subordinated guarantee.

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The indenture agreement governing EPO 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 Enterprise Products Partners nor EPO can declare or make any distributions to any of its respective equity securities or make any payments on indebtedness or other obligations that rank pari passu with or are subordinated to the EPO Junior Notes B. EPO Junior Notes B rank pari passu with the Junior Subordinated Notes A due August 2066.

The EPO Junior Notes B will bear interest at a fixed annual rate of 7.034% from May 2007 to January 2018, payable semi-annually in arrears in January and July of each year, which commenced in January 2008. After January 2018, the EPO 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 EPO 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 EPO Junior Notes B, EPO entered into a Replacement Capital Covenant in favor of the covered debt holders (as named therein) pursuant to which EPO agreed for the benefit of such debt holders that it would not 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.

During the fourth quarter of 2008, EPO retired $17.3 million of its Junior Notes B for $10.2 million. The $7.1 million gain on extinguishment of debt is included in “Other, net” on our Condensed Statement of Consolidated Operations for the year ended December 31, 2008.

Canadian Revolver. 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 (“Canadian Revolver”) with The Bank of Nova Scotia. The Canadian Revolver, 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 borrowings may be comprised of 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 Canadian Revolver 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, 2008 and 2007, there were no borrowings outstanding under this credit facility.

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Consolidated Debt Obligations of TEPPCO

The following table summarizes the principal amount of consolidated debt obligations of TEPPCO at the dates indicated:

	December 31,
	2008		2007
Senior debt obligations of TEPPCO:
TEPPCO Revolver, variable rate, due December 2012	$	516,653	$	490,000
TEPPCO Senior Notes, 7.625% fixed rate, due February 2012		500,000		500,000
TEPPCO Senior Notes, 6.125% fixed rate, due February 2013		200,000		200,000
TEPPCO Senior Notes, 5.90% fixed rate, due April 2013		250,000		--
TEPPCO Senior Notes, 6.65% fixed rate, due April 2018		350,000		--
TEPPCO Senior Notes, 7.55% fixed rate, due April 2038		400,000		--
TE Products Senior Notes, 6.45% fixed-rate, due January 2008		--		180,000
TE Products Senior Notes, 7.51% fixed-rate, due January 2028		--		175,000
Total senior debt obligations of TEPPCO		2,216,653		1,545,000
Subordinated debt obligations of TEPPCO:
TEPPCO Junior Subordinated Notes, fixed/variable rates, due June 2067		300,000		300,000
Total principal amount of debt obligations of TEPPCO	$	2,516,653	$	1,845,000

TE Products Pipeline Company, LLC (“TE Products”), TCTM, L.P., TEPPCO Midstream Companies, LLC, and Val Verde Gas Gathering Company, L.P. (collectively, the “Subsidiary Guarantors”) act as guarantors of TEPPCO’s senior notes and revolver. The Subsidiary Guarantors also act as guarantors, on a junior subordinated basis, of TEPPCO’s junior subordinated notes. TEPPCO’s debt obligations are non-recourse to the Parent Company and TEPPCO GP.

TEPPCO Revolver. This unsecured revolving credit facility has a borrowing capacity of $950.0 million. In July 2008, commitments under TEPPCO’s facility were increased from $700.0 million to $950.0 million. This credit facility matures in December 2012, but TEPPCO may request unlimited extensions of the maturity date subject to certain conditions. There is no limit on the total amount of standby letters of credit that can be outstanding under this credit facility.

Variable interest rates charged under this facility generally bear interest, at TEPPCO’s election at the time of each borrowing, at either (i) a LIBOR plus an applicable margin (as defined in the credit agreement) or (ii) the lender’s base rate as defined in the agreement.

The revolving credit agreement contains various covenants related to TEPPCO’s ability to, among other things, incur certain indebtedness; grant certain liens; make certain distributions; engage in specified transactions with affiliates; and enter into certain merger or consolidation transactions. TEPPCO must also satisfy certain financial covenants at the end of each fiscal quarter.

TEPPCO Short-Term Credit Facility. At December 31, 2007, TEPPCO had in place an unsecured short term credit agreement (the “TEPPCO Short-Term Credit Facility”) with a borrowing capacity of $1.00 billion. No amounts were borrowed under this agreement at December 31, 2007. During the first quarter of 2008, TEPPCO borrowed $1.00 billion under this credit agreement to finance the retirement of the TE Products’ senior notes, the acquisition of two marine service businesses and for other general partnership purposes. In March 2008, TEPPCO repaid amounts borrowed under this credit agreement, using proceeds from its senior notes offering, and terminated the facility.

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The following table summarizes TEPPCO’s borrowing and repayment activity under this credit agreement during the first quarter of 2008:

Borrowings, January 2008 (1)	$	355,000
Borrowings, February 2008 (2)		645,000
Repayments, March 2008		(1,000,000	)
Balance, March 27, 2008 (3)	$	--

(1) Funds borrowed to finance the retirement of TE Products’ senior notes. (2) Funds borrowed to finance TEPPCO’s marine services acquisitions and for general partnership purposes. (3) TEPPCO’s Short Term Credit Facility was terminated on March 27, 2008 upon full repayment of borrowings thereunder.

TEPPCO Senior Notes. In February 2002 and January 2003, TEPPCO issued its 7.625% Senior Notes and 6.125% Senior Notes, respectively. In March 2008, TEPPCO sold $250.0 million in principal amount of 5-year senior unsecured notes, $350.0 million in principal amount of 10-year senior unsecured notes and $400.0 million in principal amount of 30-year senior unsecured notes. The 5-year senior notes were issued at 99.922% of their principal amount, have a fixed interest rate of 5.90%, and mature in April 2013. The 10-year senior notes were issued at 99.640% of their principal amount, have a fixed interest rate of 6.65%, and mature in April 2018. The 30-year senior notes were issued at 99.451% of their principal amount, have a fixed interest rate of 7.55%, and mature in April 2038.

The senior notes issued in March 2008 pay interest semi-annually in arrears on April 15 and October 15 of each year, beginning October 15, 2008. Net proceeds from the issuance of these notes were used to repay and terminate the TEPPCO Short-Term Credit Facility. The notes issued in March 2008 rank pari passu with TEPPCO’s existing and future unsecured and unsubordinated indebtedness. They are senior to any future subordinated indebtedness of TEPPCO.

The TEPPCO Senior Notes are subject to make-whole redemption rights and are redeemable at any time at TEPPCO’s option. The indenture agreements governing these notes contain certain covenants, including, but not limited to the creation of liens securing indebtedness and sale and leaseback transactions. However, the indentures do not limit TEPPCO’s ability to incur additional indebtedness.

TE Products Senior Notes. In January 1998, TE Products issued its 6.45% Senior Notes due January 2008 and 7.51% Senior Notes due January 2028. In January 2008, the 6.45% TE Products Senior Notes matured. The $180.0 million principal amount was repaid with borrowings under TEPPCO’s Short-Term Credit Facility. In October 2007 a portion of the 7.51% Senior Notes was redeemed and in January 2008 the remaining $175.0 million was redeemed at a redemption price of 103.755% of the principal amount plus accrued interest and unpaid interest at the date of redemption. The $175.0 million principal amount was repaid with borrowings under TEPPCO’s Short-Term Credit Facility.

TEPPCO Junior Subordinated Notes. In May 2007, TEPPCO sold $300.0 million in principal amount of fixed/floating, unsecured, long-term subordinated notes due June 1, 2067 (“TEPPCO Junior Subordinated Notes”). TEPPCO used the proceeds from this subordinated debt to temporarily reduce borrowings outstanding under its Revolver and for general partnership purposes. The payment obligations under the TEPPCO Junior Subordinated Notes are subordinated to all of its current and future senior indebtedness (as defined in the related indenture).

The indenture governing the TEPPCO Junior Subordinated Notes does not limit TEPPCO’s ability to incur additional debt, including debt that ranks senior to or equally with the TEPPCO Junior Subordinated Notes. The indenture allows TEPPCO 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, (i) TEPPCO cannot declare or make any distributions to any of its respective equity securities and (ii) neither TEPPCO nor the Subsidiary Guarantors can make any payments on indebtedness or other obligations that rank pari passu with or are subordinated to the TEPPCO Junior Subordinated Notes.

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The TEPPCO Junior Subordinated Notes bear interest at a fixed annual rate of 7.0% from May 2007 to June 1, 2017, payable semi-annually in arrears. After June 1, 2017, the TEPPCO Junior Subordinated Notes will bear interest at a variable annual rate equal to the 3-month LIBOR for the related interest period plus 2.7775%, payable quarterly in arrears. The TEPPCO Junior Subordinated Notes mature in June 2067. The TEPPCO Junior Subordinated Notes are redeemable in whole or in part prior to June 1, 2017 for a “make-whole” redemption price and thereafter at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest. The TEPPCO Junior Subordinated Notes are also redeemable prior to June 1, 2017 in whole (but not in part) upon the occurrence of certain tax or rating agency events at specified redemption prices.

In connection with the issuance of the TEPPCO Junior Subordinated Notes, TEPPCO and its Subsidiary Guarantors entered into a Replacement Capital Covenant in favor of holders (as provided therein) pursuant to which TEPPCO and its Subsidiary Guarantors agreed for the benefit of such debt holders that it would not redeem or repurchase the TEPPCO Junior Subordinated Notes on or before June 1, 2037, unless such redemption or repurchase is from proceeds of issuance of certain securities.

Covenants

We were in compliance with the covenants of our consolidated debt agreements at December 31, 2008 and 2007.

Information regarding variable interest rates paid

The following table presents the range of interest rates and weighted-average interest rates paid on our consolidated variable-rate debt obligations during the year ended December 31, 2008.

	Range of	Weighted-Average
	Interest Rates	Interest Rate
	Paid	Paid
EPE Revolver	2.91% to 6.99%	4.62%
EPE Term Loan A	3.14% to 6.99%	4.57%
EPE Term Loan B	4.02% to 7.49%	5.68%
EPO Revolver	0.97% to 6.00%	3.54%
Dixie Revolver	0.81% to 5.50%	3.20%
Petal GO Zone Bonds	0.78% to 7.90%	2.24%
Duncan Energy Partners’ Revolver	1.30% to 6.20%	4.25%
Duncan Energy Partners’ Term Loan Agreement	2.93% to 2.93%	2.93%
TEPPCO Revolver	1.06% to 2.24%	1.40%
TEPPCO Short-Term Credit Facility	3.59% to 4.96%	4.02%

Consolidated debt maturity table

The following table presents scheduled maturities of our consolidated debt obligations for the next five years, and in total thereafter.

2009	$	--
2010		562,500
2011		942,750
2012		2,786,749
2013		1,208,500
Thereafter		7,139,200
Total scheduled principal payments	$	12,639,699

In accordance with SFAS 6, long-term and current maturities of debt reflect the classification of such obligations at December 31, 2008.

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Debt Obligations of Unconsolidated Affiliates

Enterprise Products Partners has two unconsolidated affiliates with long-term debt obligations and TEPPCO has one unconsolidated affiliate with long-term debt obligations. The following table shows (i) the ownership interest in each entity at December 31, 2008, (ii) total debt of each unconsolidated affiliate at December 31, 2008 (on a 100% basis to the unconsolidated affiliate) and (iii) the corresponding scheduled maturities of such debt.

				Scheduled Maturities of Debt
	Ownership													After
	Interest	Total		2009		2010		2011		2012		2013		2013
Poseidon (1)	36.0%	$	109,000	$	--	$	--	$	109,000	$	--	$	--	$	--
Evangeline (1)	49.5%		15,650		5,000		3,150		7,500		--		--		--
Centennial (2)	50.0%		129,900		9,900		9,100		9,000		8,900		8,600		84,400
Total		$	254,550	$	14,900	$	12,250	$	125,500	$	8,900	$	8,600	$	84,400

(1) Denotes an unconsolidated affiliate of Enterprise Products Partners. (2) Denotes an unconsolidated affiliate of TEPPCO.

The credit agreements of these unconsolidated affiliates include customary covenants, including financial covenants. These businesses were in compliance with such covenants at December 31, 2008. The credit agreements of these unconsolidated affiliates restrict their ability to pay cash dividends or distributions if a default or an event of default (as defined in each credit agreement) has occurred and is continuing at the time such dividend or distribution is scheduled to be paid.

The following information summarizes the significant terms of the debt obligations of these unconsolidated affiliates at December 31, 2008:

Poseidon. Poseidon has a $150.0 million variable-rate revolving credit facility that matures in May 2011. This credit agreement is secured by substantially all of Poseidon’s assets. The variable interest rates charged on this debt at December 31, 2008 and December 31, 2007 were 4.31% and 6.62%, respectively.

Evangeline. At December 31, 2008, Evangeline’s debt obligations consisted of (i) $8.2 million 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 in 2009 with a final repayment in 2010 of approximately $3.2 million.

Evangeline incurred the subordinated note payable as a result of its acquisition of a contract-based intangible asset in the early 1990s. This note is subject to a subordination agreement which prevents the repayment of principal and accrued interest on the subordinated 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 0.5%. The variable interest rates charged on this note at December 31, 2008 and December 31, 2007 were 3.20% and 5.88%, respectively. Accrued interest payable related to the subordinated note was $9.8 million and $9.1 million at December 31, 2008 and December 31, 2007, respectively.

TE Products and its joint venture partner in Centennial have each guaranteed one-half of Centennial’s debt obligations. If Centennial defaults on its debt obligations, the estimated payment

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obligation for TE Products is $65.0 million. At December 31, 2008, TE Products had recognized a liability of $9.0 million for its share of the Centennial debt guaranty.

Note 16. Partners’ Equity and Distributions

We are a Delaware limited partnership that was formed in April 2005. We are owned 99.99% by our limited partners and 0.01% by EPE Holdings, our sole general partner. EPE Holdings is owned 100% by Dan Duncan LLC, which is wholly-owned by Dan L. Duncan.

Our Units represent limited partner interests, which give the holders thereof the right to participate in cash distributions and to exercise the other rights or privileges available to them under our First Amended and Restated Agreement of Limited Partnership (as amended from time to time, the “Partnership Agreement”).

In accordance with the Partnership Agreement, capital accounts are maintained for our general partner and limited partners. The capital account provisions of the Partnership Agreement incorporate principles established for U.S. Federal income tax purposes and are not comparable to GAAP-based equity amounts presented in our consolidated financial statements. Earnings and cash distributions are allocated to holders of our Units in accordance with their respective percentage interests.

Class B and C Units

In May 2007, we issued an aggregate of 14,173,304 Class B Units and 16,000,000 Class C Units to DFI and DFIGP in connection with their contribution of 4,400,000 common units representing limited partner interest of TEPPCO and 100% of the general partner interest of TEPPCO GP. Due to common control considerations (see Note 1), the Class B and Class C Units are reflected as outstanding since February 2005, which was the period that private company affiliates of EPCO first acquired ownership interests in TEPPCO and TEPPCO GP.

On July 12, 2007, all of the outstanding 14,173,304 Class B Units were converted into Units on a one-to-one basis. While outstanding as a separate class, the Class B Units (i) entitled the holder to the allocation of income, gain, loss, deduction and credit to the same extent as such items were allocated to holders of the Parent Company’s Units, (ii) entitled the holder to share in the Parent Company’s distributions of available cash and (iii) were generally non-voting.

On February 1, 2009, all of the outstanding 16,000,000 Class C Units were converted to Units on a one-to-one basis. For financial accounting purposes, the Class C Units were not allocated any portion of net income until their conversion into Units. In addition, the Class C Units were non-participating in current or undistributed earnings prior to conversion. The Units into which the Class C Units were converted are eligible to receive cash distributions beginning with the distribution expected to be paid in May 2009.

Prior to February 1, 2009, the Class C Units (i) entitled the holder to the allocation of taxable income, gain, loss, deduction and credit to the same extent as such tax amounts were allocated to the holder if the Class C Units were converted and outstanding Units and (ii) were non-voting, except that, the Class C Units were entitled to vote as a separate class on any matter that adversely affected the rights or preferences of the Class C Units in relation to other classes of partnership interests (including as a result of a merger or consolidation) or as required by law. The approval of a majority of the Class C Units was required to approve any matter for which the holders of the Class C Units were entitled to vote as a separate class.

Private Placement of Parent Company Units

On July 17, 2007, the Parent Company completed a private placement of 20,134,220 Units to third party investors at $37.25 per Unit. The net proceeds of this private placement, after giving effect to placement agent fees, were approximately $739.0 million. The net proceeds were used to repay certain

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principal amounts outstanding under the EPE Interim Credit Facility and related accrued interest (see Note 15). Effective October 5, 2007, these Units were registered for resale.

Unit History

The following table summarizes changes in our outstanding Units since December 31, 2006:

			Class B			Class C
	Units		Units			Units
Balance, December 31, 2006		88,884,116		14,173,304			16,000,000
Conversion of Class B Units to Units in July 2007		14,173,304		(14,173,304	)		--
Units issued in connection private placement in July 2007		20,134,220		--			--
Balance, December 31, 2007 and 2008		123,191,640		--			16,000,000

Summary of Changes in Limited Partners’ Equity

The following table details the changes in limited partners’ equity since December 31, 2005:

				Class B			Class C
	Units			Units			Units		Total
Balance, December 31, 2005	$	696,224		$	373,622		$	380,665	$	1,450,511
Net income		92,559			41,420			--		133,979
Distributions to partners		(108,438	)		--			--		(108,438	)
Distributions to former owners		--			(57,960	)		--		(57,960	)
Operating leases paid by EPCO		109			--			--		109
Amortization of equity awards		80			--			--		80
Contributions		755			--			--		755
Acquisition related disbursement of cash		(319	)		--			--		(319	)
Change in accounting methods of equity awards		(48	)		--			--		(48	)
Balance, December 31, 2006		680,922			357,082			380,665		1,418,669
Net income		75,624			33,386			--		109,010
Operating leases paid by EPCO		107			--			--		107
Distributions to partners		(159,028	)		--			--		(159,028	)
Distributions to former owners		--			(29,760	)		--		(29,760	)
Conversions of Class B Units		360,708			(360,708	)		--		--
Amortization of equity awards		530			--			--		530
Contributions		739,458			--			--		739,458
Balance, December 31, 2007		1,698,321			--			380,665		2,078,986
Net income		164,039			--			--		164,039
Operating leases paid by EPCO		103			--			--		103
Distributions to partners		(213, 097	)		--			--		(213,097	)
Amortization of equity awards		1,133			--			--		1,133
Acquisition of treasury units by subsidiary, net
of minority interest amount of $1,873		(38	)		--			--		(38	)
Balance, December 31, 2008	$	1,650,461		$	--		$	380,665	$	2,031,126

Our limited partner’s equity accounts reflect the issuance of the Class B and C Units in February 2005, which was the month in which the TEPPCO and TEPPCO GP interests were first acquired by private company affiliates of EPCO. The total value of the units issued represents the purchase price paid for the acquired TEPPCO and TEPPCO GP interests and was allocated between the Class B Units and Class C Units based on the relative market value of the Class B and Class C Units at the time of issuance. The relative market value of the Class B Units was determined by reference to the closing prices of the Parent Company’s Units for the five day period beginning two trading days prior to May 7, 2007 and ending two trading days thereafter. The value of the Class C Units represents a discount to the initial value of the Class B Units since the Class C Units are non-participating in current or undistributed earnings and are not entitled to receive cash distributions until May 2009.

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Distributions to Partners

The Parent Company’s cash distribution policy is consistent with the terms of its Partnership Agreement, which requires it to distribute its available cash (as defined in our Partnership Agreement) to its partners no later than 50 days after the end of each fiscal quarter. The quarterly cash distributions are not cumulative.

The following table presents the Parent Company’s declared quarterly cash distribution rates per Unit since the first quarter of 2007 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 50 days after the end of such fiscal quarter.

	Cash Distribution History
	Distribution	Record	Payment
	per Unit	Date	Date
2007
1st Quarter	$0.365	Apr. 30, 2007	May 11, 2007
2nd Quarter	$0.380	Jul. 31, 2007	Aug. 10, 2007
3rd Quarter	$0.395	Oct. 31, 2007	Nov. 9, 2007
4th Quarter	$0.410	Jan. 31, 2008	Feb. 8, 2008
2008
1st Quarter	$0.425	Apr. 30, 2008	May 8, 2008
2nd Quarter	$0.440	Jul. 31, 2008	Aug. 8, 2008
3rd Quarter	$0.455	Oct. 31, 2008	Nov. 13, 2008
4th Quarter	$0.470	Jan. 30, 2009	Feb. 10, 2009

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss primarily includes the effective portion of the gain or loss on financial instruments designated and qualified as a cash flow hedge, foreign currency adjustments and Dixie’s minimum pension liability adjustments. Amounts accumulated in other comprehensive loss from cash flow hedges are reclassified into earnings in the same period(s) in which the hedged forecasted transactions (such as a forecasted forward sale of NGLs) affect earnings. If it becomes probable that the forecasted transaction will not occur, the net gain or loss in accumulated other comprehensive loss must be immediately reclassified. See Note 8 for additional information regarding our financial instruments and related hedging activities.

The following table presents the components of accumulated other comprehensive loss at the balance sheet dates indicated:

	At December 31,
	2008			2007
Commodity financial instruments – cash flow hedges (1)	$	(114,087	)	$	(40,271	)
Interest rate financial instruments – cash flow hedges (1)		(66,560	)		1,048
Foreign currency cash flow hedges (1)		10,594			1,308
Foreign currency translation adjustment (2)		(1,301	)		1,200
Pension and postretirement benefit plans (3)		(751	)		588
Proportionate share of other comprehensive loss of
unconsolidated affiliates, primarily Energy Transfer Equity		(13,723	)		(3,848	)
Total accumulated other comprehensive loss	$	(185,828	)	$	(39,975	)

(1) See Note 8 for additional information regarding these components of accumulated other comprehensive income (loss). (2) Relates to transactions of Enterprise Products Partners’ Canadian NGL marketing subsidiary. (3) See Note 7 for additional information regarding Dixie’s pension and postretirement benefit plans.

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Other

In October 2006, EPO 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 paid for this business (which was under common control with us) exceeded the carrying values of the assets acquired and liabilities assumed by $6.3 million, of which $0.3 million was allocated to us and $6.0 million to minority interest. Our share of 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 Consolidated 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.

Note 17. Related Party Transactions

The following table summarizes our revenue and expense transactions with related parties for the periods indicated:

	For Year Ended December 31,
	2008		2007		2006

Revenues from consolidated operations:
EPCO and affiliates	$	6	$	6	$	55,809
Energy Transfer Equity		618,370		294,627		--
Other unconsolidated affiliates		396,874		290,418		304,854
Total	$	1,015,250	$	585,051	$	360,663
Operating costs and expenses:
EPCO and affiliates	$	453,537	$	387,647	$	403,825
Energy Transfer Equity		192,159		35,156		--
Cenac and affiliates		45,381		--		--
Other unconsolidated affiliates		56,160		41,034		39,884
Total	$	747,237	$	463,837	$	443,709
General and administrative costs:
EPCO and affiliates	$	91,810	$	82,467	$	63,465
Cenac and affiliates		2,913		--		--
Total	$	94,723	$	82,467	$	63,465
Other expense:
EPCO and affiliates	$	274	$	170	$	--

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 includes the following significant entities that are not part of our consolidated group of companies:

§	EPCO and its consolidated private company subsidiaries;

§	EPE Holdings, our general partner; and

§	the Employee Partnerships (see Note 6).

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In December 2006, at a special meeting of TEPPCO’s unitholders, its partnership agreement was amended and restated, and its general partner’s maximum percentage interest in its quarterly distributions was reduced from 50.0% to 25.0% in exchange for 14,091,275 common units. Certain of the IDRs held by TEPPCO GP were converted into 14,091,275 common units of TEPPCO. Subsequently, DFIGP transferred the 14,091,275 common units of TEPPCO that it received in connection with the conversion of the IDRs to affiliates of EPCO, including 13,386,711 common units transferred to DFI.

The Parent Company, EPE Holdings, TEPPCO, TEPPCO GP, Enterprise Products Partners and EPGP are separate legal entities apart from each other and apart from EPCO and its other affiliates, with assets and liabilities that are separate from those of EPCO and its other affiliates. EPCO and its private company subsidiaries depend on the cash distributions they receive from the Parent Company, TEPPCO, Enterprise Products Partners and other investments to fund their other operations and to meet their debt obligations. EPCO and its private company affiliates received directly from us $439.8 million, $388.9 million and $306.5 million in cash distributions during the years ended December 31, 2008, 2007 and 2006, respectively.

An affiliate of EPCO provides us trucking services for the transportation of NGLs and other products. We paid this trucking affiliate $21.7 million, $19.1 million and $20.7 million for its services during the years ended December 31, 2008, 2007 and 2006, respectively.

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, 2008, 2007 and 2006, we paid EPCO $7.8 million, $7.8 million and $3.7 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. Enterprise Products Partners acquired this affiliate in October 2006 and began consolidating its financial statements with those of our own from the date of acquisition.

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 the ASA. Enterprise Products Partners and its general partner, the Parent Company and its general partner, Duncan Energy Partners and its general partner, and TEPPCO and its general partner, among other affiliates, are parties to the ASA. The Audit Conflicts and Governance Committees of each general partner have approved 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 business, properties and assets (in

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accordance with prudent industry practices). EPCO will employ or otherwise retain the services of such personnel as may be necessary to provide such services.

§	EPCO will allow us to participate as a named insured in its overall insurance program with the associated premiums and other costs being allocated to us.

Under the ASA, EPCO subleases to Enterprise Products Partners (for $1 per year) certain equipment which it holds pursuant to operating leases and has assigned to Enterprise Products Partners its purchase option under such leases (the “retained leases”). EPCO remains liable for the actual cash lease payments associated with these agreements. Enterprise Products Partners records the full value of these payments made by EPCO on Enterprise Products Partners’ behalf as a non-cash related party operating lease expense, with the offset to partners’ equity accounted for as a general contribution to its partnership. Enterprise Products Partners exercised its election under the retained leases to purchase a cogeneration unit in December 2008 for $2.3 million. Should Enterprise Products Partners decide to exercise the purchase option associated with the remaining agreement, it would pay the original lessor $3.1 million in June 2016.

Our operating costs and expenses for the three the years ended December 31, 2008, 2007 and 2006 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 $451.5 million, $385.5 million and $401.7 million during the years ended December 31, 2008, 2007 and 2006, respectively.

Likewise, our general and administrative costs for the years ended December 31, 2008, 2007 and 2006 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 the 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 $91.9 million, $82.5 million and $63.5 million during the years ended December 31, 2008, 2007 and 2006, respectively.

Since the vast majority of such expenses are charged to us on an actual basis (i.e. no mark-up or subsidy is charged or received by EPCO), we believe that such expenses are representative of what the amounts would have been on a stand alone basis. With respect to allocated costs, we believe that the proportional direct allocation method employed by EPCO is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis.

§	general partner interests (or securities which have characteristics similar to general partner interests) and IDRs or similar rights in publicly traded partnerships or interests in persons that

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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

The Parent Company will be presumed to desire to acquire the equity securities until such time as EPE Holdings advises the EPCO Group, EPGP and DEP GP that the Parent Company 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 $100.0 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 Audit, Conflicts and Governance (“ACG”) Committee of EPE Holdings. If the purchase price is reasonably likely to be less than such threshold amount, the chief executive officer of EPE Holdings may make the determination to decline the acquisition without consulting the ACG Committee of EPE Holdings.

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in accordance with the procedures described above, and shall have advised the EPCO Group that we have abandoned the pursuit of such acquisition.

The ASA was amended on January 30, 2009 to provide for the cash reimbursement by TEPPCO, Enterprise Products Partners, Duncan Energy Partners and the Parent Company to EPCO of distributions of cash or securities, if any, made by TEPPCO Unit II or EPCO Unit to their respective Class B limited partners. The ASA amendment also extended the term under which EPCO provides services to the partnership entities from December 2010 to December 2013 and made other updating and conforming changes.

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, Enterprise Products Partners’ common units and TEPPCO’s common units. See Note 6 for additional information regarding the Employee Partnerships.

Relationships with Unconsolidated Affiliates

The following information summarizes significant related party transactions with our current unconsolidated affiliates:

Enterprise Products Partners sells 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 totaled $362.9 million, $268.0 million and $277.7 million for the years ended December 31, 2008, 2007 and 2006, respectively. In addition, Duncan Energy Partners furnished $1.0 million in letters of credit on behalf of Evangeline at December 31, 2008.

Enterprise Products Partners pays Promix for the transportation, storage and fractionation of NGLs. In addition, Enterprise Products Partners sells natural gas to Promix for its plant fuel requirements. Expenses with Promix were $38.7 million, $30.4 million and $34.9 million for the years ended December 31, 2008, 2007 and 2006, respectively. Revenues from Promix were $24.5 million, $17.3 million and $21.8 million for the years ended December 31, 2008, 2007 and 2006, respectively.

§	We perform management services for certain of our unconsolidated affiliates. We charged such affiliates $11.2 million, $11.0 million and $10.3 million for the years ended December 31, 2008, 2007 and 2006, respectively.

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For the years ended December 31, 2008, 2007 and 2006, TEPPCO paid $1.7 million, $3.8 million and $5.6 million, respectively, to Centennial in connection with a pipeline capacity lease. In addition, TEPPCO paid $6.6 million and $5.3 million to Centennial in 2008 and 2007 for other pipeline transportation services, respectively.

§	For the years ended December 31, 2008, 2007 and 2006, TEPPCO paid Seaway $6.0 million, $4.7 million and $3.8 million, respectively, for transportation and tank rentals in connection with its crude oil marketing activities.

Enterprise Products Partners has a long-term sales contract with a consolidated subsidiary of ETP. In addition, Enterprise Products Partners and another subsidiary of ETP transport natural gas on each other’s systems and share operating expenses on certain pipelines. A subsidiary of ETP also sells natural gas to Enterprise Products Partners. See previous table for revenue and expense amounts recorded by Enterprise Products Partners in connection with Energy Transfer Equity.

Relationship with Duncan Energy Partners

In September 2006, Duncan Energy Partners, a consolidated subsidiary of Enterprise Products Partners, was formed 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 at $21.00 per unit, which generated net proceeds to Duncan Energy Partners of approximately $291.0 million. On this same date, Enterprise Products Partners contributed 66.0% of its equity interests in certain of its subsidiaries to Duncan Energy Partners. Enterprise Products Partners retained the remaining 34.0% equity interests in the subsidiaries. As consideration for assets contributed and reimbursement for capital expenditures related to these assets, Duncan Energy Partners distributed $260.6 million of net proceeds from its initial public offering 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).

At December 31, 2008, Enterprise Products Partners owned 74.1% of Duncan Energy Partners’ limited partner interests and all of its general partner interest.

Relationship with Cenac

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repairs and maintenance expenses and insurance premiums on the equipment. During 2008, TEPPCO paid Cenac approximately $48.3 million in connection with the transitional operating agreement.

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 Margin 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 Year Ended December 31,
	2008		2007		2006
Current:
Federal	$	4,922	$	4,700	$	7,694
State		23,932		5,107		1,148
Foreign		414		128		--
Total current		29,268		9,935		8,842
Deferred:
Federal		760		2,784		6,109
State		964		3,094		7,023
Foreign		27		--		--
Total deferred		1,751		5,878		13,132
Total provision for income taxes	$	31,019	$	15,813	$	21,974

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 Year Ended December 31,
	2008			2007			2006
Pre Tax Net Book Income (“NBI”)	$	1,176,532		$	777,709		$	794,458

Revised Texas franchise tax		23,890			7,703			8,770
State income taxes (net of federal benefit)		577			324			(396	)
Federal income taxes computed by applying the federal
statutory rate to NBI of corporate entities		6,305			5,318			13,347
Taxes charged to cumulative effect of change
in accounting principle		--			--			(3	)
Valuation allowance		(1,412	)		2,347			123
Other permanent differences		1,659			121			133
Provision for income taxes	$	31,019		$	15,813		$	21,974
Effective income tax rate		2.6	%		2.0	%		2.8	%

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Significant components of deferred tax liabilities and deferred tax assets as of December 31, 2008 and 2007 are as follows:

	December 31,
	2008			2007
Deferred tax assets:
Net operating loss carryovers	$	26,311		$	23,270
Property, plant and equipment		753			--
Credit carryover		26			26
Charitable contribution carryover		20			16
Employee benefit plans		2,631			3,214
Deferred revenue		964			642
Reserve for legal fees and damages		289			478
Equity investment in partnerships		596			409
AROs		76			80
Accruals and other		900			1,098
Total deferred tax assets		32,566			29,233
Valuation allowance		(3,932	)		(5,345	)
Net deferred tax assets		28,634			23,888
Deferred tax liabilities:
Property, plant and equipment		92,899			40,520
Other		52			99
Total deferred tax liabilities		92,951			40,619
Total net deferred tax liabilities	$	(64,317	)	$	(16,731	)

Current portion of total net deferred tax assets	$	1,397		$	1,082
Long-term portion of total net deferred tax liabilities	$	(65,714	)	$	(17,813	)

We had net operating loss carryovers of $26.3 million and $23.3 million at December 31, 2008 and 2007, respectively. These losses expire in various years between 2009 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 $3.9 million and $5.3 million at December 31, 2008 and 2007, 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 $1.4 million decrease in valuation allowance for 2008 is comprised primarily of a $1.6 million decrease for Canadian Enterprise Gas Products, Ltd..

We have deferred tax liabilities on property plant and equipment of $92.9 million and $40.5 million at December 31, 2008 and 2007, respectively. The increase in 2008 is comprised primarily of $45.1 million related to the difference in book and tax basis of property, plant and equipment resulting from the acquisition of the remaining equity interest in Dixie. See Note 13 for additional information regarding this acquisition.

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 liability companies, limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70.0% 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 $0.9 million and $3.1 million during the years ended December 31, 2008 and 2007, respectively. The offsetting net charge of $0.9 million and $3.1 million is shown on our Statements of Consolidated Operations for the years ended December 31, 2008 and 2007, respectively, as a component of “Provision for income taxes.”

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Note 19. Earnings Per Unit

Basic and diluted earnings per unit is computed by dividing net income or loss allocated to limited partners by the weighted-average number of Units outstanding during a period, including Class B Units (see below). The amount of net income allocated to limited partners is derived by subtracting, from net income or loss, our general partner’s share of such net income or loss.

As consideration for the contribution of 4,400,000 common units of TEPPCO and the 100% membership interest in TEPPCO GP (including associated TEPPCO IDRs), the Parent Company issued 14,173,304 Class B Units and 16,000,000 Class C Units to private company affiliates of EPCO that are under common control with the Parent Company. As a result of this common control relationship, the Class B Units, which were distribution bearing, were treated as outstanding securities for purposes of calculating our basic and diluted earnings per Unit. On July 12, 2007, all of the outstanding 14,173,304 Class B Units were converted to Units on a one-to-one basis. The 16,000,000 Class C Units are non-participating in current or undistributed earnings and are not entitled to receive cash distributions until May 2009; thus, they are not considered a potentially dilutive security until that time. See Note 16 for additional information regarding the Class B and C Units.

The following table shows the allocation of net income to our general partner for the periods indicated:

	For Year Ended December 31,
	2008			2007			2006
Net income	$	164,055		$	109,021		$	133,992
Multiplied by general partner ownership interest		0.01	%		0.01	%		0.01	%
General partner interest in net income	$	16		$	11		$	13

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The following table shows the calculation of our limited partners’ interest in net income and basic and diluted earnings per Unit.

	For Year Ended December 31,
	2008			2007			2006
Income before change in accounting principle
and general partner interest	$	164,055		$	109,021		$	133,899
Cumulative effect of change in accounting principle		--			--			93
Net income		164,055			109,021			133,992
General partner interest in net income		(16	)		(11	)		(13	)
Net income available to limited partners	$	164,039		$	109,010		$	133,979

BASIC AND DILUTED EARNINGS PER UNIT
Numerator:
Income before change in accounting principle
and general partner interest	$	164,055		$	109,021		$	133,899
Cumulative effect of change in accounting principle		--			--			93
General partner interest in net income		(16	)		(11	)		(13	)
Limited partners' interest in net income	$	164,039		$	109,010		$	133,979
Denominator:
Units		123,192			104,869			88,884
Class B Units		--			7,456			14,173
Total		123,192			112,325			103,057
Basic and diluted earnings per Unit:
Income before change in accounting principle
and general partner interest	$	1.33		$	0.97		$	1.30
Cumulative effect of change in accounting principle		--			--			*
General partner interest in net income		*			*			*
Limited partners’ interest in net income	$	1.33		$	0.97		$	1.30

* Amount is negligible

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

Parent Company matters. In February 2008, Joel A. Gerber, a purported unitholder of the Parent Company, filed a derivative complaint on behalf of the Parent Company in the Court of Chancery of the State of Delaware. The complaint names as defendants EPE Holdings; the Board of Directors of EPE Holdings; EPCO; and Dan L. Duncan and certain of his affiliates. The Parent Company is named as a nominal defendant. The complaint alleges that the defendants, in breach of their fiduciary duties to the Parent Company and its unitholders, caused the Parent Company to purchase in May 2007 the TEPPCO GP membership interests and TEPPCO common units from Mr. Duncan’s affiliates at an unfair price. The complaint also alleges that Charles E. McMahen, Edwin E. Smith and Thurmon Andress, constituting the three members of EPE Holdings’ ACG Committee, cannot be considered independent because of their relationships with Mr. Duncan. The complaint seeks relief (i) awarding damages for profits allegedly obtained by the defendants as a result of the alleged wrongdoings in the complaint and (ii) awarding

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plaintiff costs of the action, including fees and expenses of his attorneys and experts. Management believes this lawsuit is without merit and intends to vigorously defend against it. For information regarding our relationship with Mr. Duncan and his affiliates, see Note 17.

Enterprise Products Partners’ matters. In February 2007, EPO received a letter from the Environment and Natural Resources Division (“ENRD”) of the U.S. Department of Justice (“DOJ”) related to an ammonia release in Kingman County, Kansas in October 2004 from a pressurized anhydrous ammonia pipeline owned by a third party, Magellan Ammonia Pipeline, L.P. (“Magellan”) and a previous release of ammonia in September 2004 from the same pipeline. EPO was the operator of this pipeline until July 1, 2008. 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. At this time, we do not believe that a final resolution of the civil claims by the ENRD will have a material impact on Enterprise Products Partners’ consolidated financial position, results of operations or cash flows.

In October 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 Enterprise Products Partners’ consolidated financial position, results of operations or cash flows.

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

The Attorney General of Colorado on behalf of the Colorado Department of Public Health and Environment filed suit against Enterprise Products Partners and others in April 2008 in connection with the construction of a pipeline near Parachute, Colorado. The State sought a temporary restraining order and an injunction to halt construction activities since it alleged that the defendants failed to install measures to minimize damage to the environment and to follow requirements for the pipeline’s stormwater permit and appropriate stormwater plan. The State’s complaint also seeks penalties for the above alleged failures. Defendants and the State agreed to certain stipulations that, among other things, require Enterprise Products Partners to install specified environmental protection measures in the disturbed pipeline right-of-way to comply with regulations. Enterprise Products Partners has complied with the stipulations and the State has dismissed the portions of the compliant seeking the temporary restraining order and injunction. The State has not yet assessed penalties and we are unable to predict the amount of penalties that may be assessed. At this time, we do not believe that this incident will have a material impact on our consolidated financial position, results of operations or cash flows.

In January 2009, the State of New Mexico filed suit in District Court in Santa Fe County, New Mexico, under the New Mexico Air Quality Control Act. The lawsuit arose out of a February 27, 2008 Notice Of Violation issued to Marathon as operator of the Indian Basin natural gas processing facility located in Eddy County, New Mexico. Enterprise Products Partners owns a 40.0% undivided interest in the assets comprising the Indian Basin facility. The State alleges violations of its air laws, and Marathon believes there has been no adverse impact to public health or the environment, having implemented voluntary emission reduction measures over the years. The State seeks penalties above $100,000. Marathon continues to work with the State to determine if resolution of the case is possible.

TEPPCO matters. In September 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 Enterprise Products

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Partners or its affiliates. In July 2007, Mr. Brinkerhoff filed an amended complaint. The amended complaint names as defendants (i) TEPPCO, its current and certain former directors, and certain of its affiliates; (ii) Enterprise Products Partners and certain of its affiliates; (iii) EPCO; and (iv) Dan L. Duncan.

The amended complaint alleges, among other things, that the defendants caused TEPPCO to enter into certain transactions that were unfair to TEPPCO or otherwise unfairly favored Enterprise Products Partners or its affiliates over TEPPCO. These transactions are alleged to include: (i) the joint venture to further expand the Jonah system entered into by TEPPCO and Enterprise Products Partners in August 2006; (ii) the sale by TEPPCO of its Pioneer natural gas processing plant to Enterprise Products Partners in March 2006; and (iii) certain amendments to TEPPCO’s partnership agreement, including a reduction in the maximum tier of TEPPCO’s IDRs in exchange for TEPPCO common units. The amended complaint seeks (i) rescission of the amendments to TEPPCO’s partnership agreement; (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. Pre-trial discovery in this proceeding is underway. We believe that the outcome of this lawsuit will not have a material effect on TEPPCO’s financial position, results of operations or cash flows.

Energy Transfer Equity matters. In July 2007, ETP announced that it was under investigation by the Commodity Futures Trading Commission (“CFTC”) with respect to whether ETP engaged in manipulation or improper trading activities in the Houston Ship Channel market around the time of the hurricanes in the fall of 2005 and other prior periods in order to benefit financially from commodity financial instrument positions and from certain index-priced physical gas purchases in the Houston Ship Channel market. In March 2008, ETP entered into a consent order with the CFTC. Pursuant to this consent order, ETP agreed to pay the CFTC $10.0 million and the CFTC agreed to release ETP and its affiliates, directors and employees from all claims or causes of action asserted by the CFTC in this proceeding. ETP neither admitted nor denied the allegations made by the CFTC in this proceeding. The settlement was paid in March 2008.

In July 2007, ETP announced that it was also under investigation by the FERC for the same matters noted in the CFTC proceeding described above. The FERC is also investigating certain of ETP’s intrastate transportation activities. The FERC’s actions against ETP also included allegations related to its Oasis pipeline, which is an intrastate pipeline that transports natural gas between the Waha and Katy hubs in Texas. The Oasis pipeline transports interstate natural gas pursuant to NGPA Section 311 authority, and is subject to FERC-approved rates, terms and conditions of service. The allegations related to the Oasis pipeline included claims that the pipeline violated NGPA regulations from January 2004 through June 2006 by granting undue preference to ETP’s affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation.

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administrative law judges with respect to the FERC’s intrastate transportation claims and market manipulation claims. The hearing related to the intrastate transportation claims involving the Oasis pipeline was scheduled to commence in December 2008 with the administrative law judge’s initial decision due in May 2009; however, as discussed below, ETP entered into a settlement agreement with FERC Enforcement Staff and that agreement was approved by the FERC in its entirety and without modification on February 27, 2009. The hearing related to the market manipulation claims is scheduled to commence in June 2009 with the administrative law judge’s initial decision due in December 2009. The FERC denied ETP’s request for dismissal of the proceeding and has ordered that, following completion of the hearings, the administrative law judge make recommendations with respect to whether ETP engaged in market manipulation in violation of the Natural Gas Act and FERC regulations, and, whether ETP violated the Natural Gas Policy Act (“NGPA”) and FERC regulations related to ETP’s intrastate transportation activities. The FERC reserved for itself the issues of possible civil penalties, revocation of ETP’s blanket market certificate, method by which ETP would disgorge any unjust profits and whether any conditions should be placed on ETP’s NGPA Section 311 authorization. Following the issuance of each of the administrative law judges’ initial decisions, the FERC would then issue an order with respect to each of these matters. ETP management has stated that it expects that the FERC will require a payment in order to conclude these investigations on a negotiated settlement basis.

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consolidation order, the plaintiffs who had filed these two earlier class actions filed a consolidated complaint. They have requested certification of their suit as a class action, unspecified damages, court costs and other appropriate relief. In January 2008, ETP filed a motion to dismiss this suit on the grounds of failure to allege facts sufficient to state a claim. In March 2008, the plaintiffs filed a second consolidated class action complaint. In response to this new pleading, ETP filed a motion to dismiss this second consolidated complaint in May 2008. In June 2008, the plaintiffs filed a response opposing ETP’s motion to dismiss. ETP filed a reply in support of its motion in July 2008.

ETP disclosed in its Form 10-K for the year ended December 31, 2008 that its accrued amounts for contingencies and current litigation matters (excluding environmental matters) aggregated $20.8 million at December 31, 2008. Since ETP’s accrual amounts are non-cash, any cash payment of an amount in resolution of these matters would likely be made from its operating cash flows or from borrowings. If these payments are substantial, ETP and, ultimately, our investee, Energy Transfer Equity, may experience a material adverse impact on their results of operations, cash available for distribution and liquidity.

Contractual Obligations

The following table summarizes our various contractual obligations at December 31, 2008. A description of each type of contractual obligation follows.

	Payment or Settlement due by Period
Contractual Obligations	Total		2009		2010		2011		2012		2013		Thereafter
Scheduled maturities of long-term debt	$	12,639,699	$	--	$	562,500	$	942,750	$	2,786,749	$	1,208,500	$	7,139,200
Estimated cash interest payments	$	12,303,887	$	755,617	$	731,020	$	678,136	$	633,640	$	503,474	$	9,002,000
Operating lease obligations	$	388,291	$	44,901	$	38,233	$	37,596	$	36,169	$	30,692	$	200,700
Purchase obligations:
Product purchase commitments:
Estimated payment obligations:
Crude oil	$	161,194	$	161,194	$	--	$	--	$	--	$	--	$	--
Refined products	$	1,642	$	1,642	$	--	$	--	$	--	$	--	$	--
Natural gas	$	5,225,141	$	323,309	$	515,102	$	635,000	$	660,626	$	487,984	$	2,603,120
NGLs	$	1,923,792	$	969,870	$	136,422	$	136,250	$	136,250	$	136,250	$	408,750
Petrochemicals	$	1,746,138	$	685,643	$	376,636	$	247,757	$	181,650	$	86,768	$	167,684
Other	$	66,657	$	24,221	$	7,148	$	7,011	$	6,699	$	6,166	$	15,412
Underlying major volume commitments:
Crude oil (in MBbls)		3,404		3,404		--		--		--		--		--
Refined products (in MBbls)		28		28		--		--		--		--		--
Natural gas (in BBtus)		981,955		56,650		93,150		115,925		120,780		93,950		501,500
NGLs (in MBbls)		56,622		23,576		4,726		4,720		4,720		4,720		14,160
Petrochemicals (in MBbls)		67,696		24,949		13,420		10,428		7,906		3,759		7,234
Service payment commitments	$	534,426	$	57,289	$	51,251	$	49,501	$	47,025	$	46,142	$	283,218
Capital expenditure commitments	$	786,675	$	786,675	$	--	$	--	$	--	$	--	$	--

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Scheduled Maturities of Long-Term Debt. The Parent Company, Enterprise Products Partners and TEPPCO have payment obligations under debt agreements. With respect to this category, amounts shown in the preceding table represent scheduled principal payments due in each period as of December 31, 2008. See Note 15 for information regarding our consolidated debt obligations at December 31, 2008.

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, 2008, 2007 or 2006; 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 retained leases contributed to Enterprise Products Partners by EPCO at Enterprise Products Partners’ formation. EPCO remains liable for the actual cash lease payments associated with these agreements, which it accounts for as operating leases. At December 31, 2008, the retained leases were for approximately 100 railcars. EPCO’s minimum future rental payments under these leases are $0.7 million for each of the years 2009 through 2015 and $0.3 million for 2016. Enterprise Products Partners records the full value of these payments made by EPCO on Enterprise Products Partners’ behalf as a non-cash related party operating lease expense, with the offset to partners’ equity accounted for as a general contribution to Enterprise Products Partners’ 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 Enterprise Products Partners. Enterprise Products Partners has exercised its election under the retained leases to purchase a cogeneration unit in December 2008 for $2.3 million. Should Enterprise Products Partners decide to exercise the purchase option associated with the remaining agreement, it would pay the original lessor $3.1 million in June 2016.

Lease and rental expense included in costs and expenses was $56.8 million, $61.4 million and $64.9 million during the years ended December 31, 2008, 2007 and 2006, 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, 2008 applied to all future volume commitments. Actual future payment obligations may vary depending on market prices at the

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time of delivery. At December 31, 2008, we do not have any significant 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 order to fund its obligations under the EPCO 1998 Plan and EPD 2008 LTIP (see Note 6), EPCO may purchase common units of Enterprise Products Partners at fair value either in the open market or directly from Enterprise Products Partners. When EPCO employees exercise options awarded under the EPCO 1998 Plan and EPD 2008 LTIP, Enterprise Products Partners reimburses EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the common units. Such reimbursements totaled $0.6 million, $3.0 million and $1.8 million during the years ended December 31, 2008, 2007, and 2006, respectively, and are reflected as a component of “Distributions paid to minority interests” in our Consolidated Statements of Cash Flows.

At December 31, 2008, there were 2,168,500 and 795,000 unit options outstanding under the EPCO 1998 Plan and EPD 2008 LTIP, respectively, for which Enterprise Products Partners is responsible for reimbursing EPCO for the costs of such awards. The weighted-average strike price of option awards outstanding at December 31, 2008 was $26.32 and $30.93 per common unit under the EPCO 1998 Plan and EPD 2008 LTIP, respectively. At December 31, 2008, there were 548,500 unit options immediately exercisable under the EPCO 1998 Plan. An additional 365,000, 480,000 and 775,000 of these unit options will be exercisable in 2009, 2010 and 2012, respectively under the EPCO 1998 Plan. The 795,000 unit options outstanding under the EPD 2008 LTIP will become exercisable in 2013. See Note 6 for additional information regarding the EPCO 1998 Plan and EPD 2008 LTIP.

In order to fund obligations under the TEPPCO 2006 LTIP, EPCO may purchase common units of TEPPCO at fair value either in the open market or directly from TEPPCO. When EPCO employees exercise options awarded under the TEPPCO 2006 LTIP, TEPPCO will reimburse EPCO for the cash difference between the strike price paid by the employee and the actual purchase price paid by EPCO for the common units. TEPPCO was committed to issue 355,000 of its common units at December 31, 2008, respectively, if all outstanding options awarded under the 2006 LTIP (as of this date) were exercised. The weighted-average strike price of option awards outstanding at December 31, 2008 was $40.00 per common unit. There were no options immediately exercisable under the 2006 LTIP at December 31, 2008. See Note 6 for additional information regarding the TEPPCO 2006 LTIP.

Other Commitments and Claims

Redelivery Commitments. In our normal business activities, we process, store and transport natural gas, NGLs and other hydrocarbon products for third parties. These volumes are (i) accrued as product payables on our Consolidated Balance Sheets, (ii) 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 terms of our storage agreements, we are generally required to redeliver volumes to the owners on demand. At December 31, 2008, Enterprise Products Partners’ redelivery commitments aggregated 29.6 million barrels (“MMBbls”) of NGL and petrochemical products and 18.5 BBtus of natural gas. TEPPCO’s redelivery commitments at this date aggregated 16.5 MMBbls of petroleum products. See Note 2 for more information regarding accrued product payables.

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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, 2008, claims against us totaled approximately $15.4 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 the 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.

Centennial Guarantees. TEPPCO has certain guarantee obligations in connection with its ownership interest in Centennial. TEPPCO has guaranteed one-half of Centennial’s debt obligations, which obligates TEPPCO to an estimated payment of $65.0 million in the event of default by Centennial. At December 31, 2008, TEPPCO had a liability of $9.0 million representing the estimated fair value of its share of the Centennial debt guaranty. See Note 15 for additional information regarding Centennial’s debt obligations.

In lieu of Centennial procuring insurance to satisfy third-party liabilities arising from a catastrophic event, TEPPCO and Centennial’s other joint venture partner have entered a limited cash call agreement. TEPPCO is obligated to contribute up to a maximum of $50.0 million in proportion to its ownership interest in Centennial in the event of a catastrophic event. At December 31, 2008, TEPPCO had a liability of $3.9 million representing the estimated fair value of its cash call guaranty. We insure against catastrophic events. Cash contributions by TEPPCO to Centennial under the limited cash call agreement may be covered by our insurance depending on the nature of the catastrophic event.

Note 21. Significant Risks and Uncertainties

Weather-Related Risks

We participate as a named insured in EPCO’s insurance program, which provides us with property damage, business interruption and other coverages, the scope and amounts of which are customary and sufficient for the nature and extent of our operations. While we believe EPCO maintains adequate insurance coverage on our behalf, insurance will not cover every type of damage or interruption that might occur. 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, results of operations and cash flows. In addition, the proceeds of any such insurance may not be paid in a timely manner and may be insufficient to reimburse us for our 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 our partners and, accordingly, adversely affect the market price of our common units.

To qualify for business interruption coverage in connection with a windstorm event, covered assets must be out-of-service in excess of 60 days for onshore assets and 75 days for offshore assets. To qualify for business interruption coverage in connection with a non-windstorm event, covered onshore and offshore assets must be out-of-service in excess of 60 days.

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

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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 year ended December 31, 2008, Enterprise Products Partners did not receive any reimbursements from insurance carriers related to property damage claims associated with this storm. During the year ended December 31, 2007 Enterprise Products Partners received cash reimbursements from insurance carriers totaling $1.3 million related to property damage claims. If the final recovery of funds is different than the amount previously expended, Enterprise Products Partners will recognize an income impact at that time.

Enterprise Products Partners has submitted business interruption insurance claims for its estimated losses caused by Hurricane Ivan, which struck the eastern U.S. Gulf Coast region in September 2004. During the year ended December 31, 2008, Enterprise Products Partners did not receive and proceeds from these claims. During the year ended December 31, 2007, Enterprise Products Partners received $0.4 million of nonrefundable cash proceeds from such claims. Enterprise Products Partners is continuing its efforts to collect residual balances from this storm. To the extent Enterprise Products Partners receives nonrefundable cash proceeds from business interruption insurance claims, these proceeds 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 Enterprise Products Partners’ Gulf Coast assets in August and September of 2005, respectively. With respect to these storms, Enterprise Products Partners has $30.5 million of estimated property damage claims outstanding at December 31, 2008, that it believes are probable of collection during the period 2009. Enterprise Products Partners continues to pursue collection of its property damage claims related to these named storms. As of December 31, 2008, Enterprise Products Partners had received all proceeds from its business interruption claims related to these storm events.

Hurricanes Gustav and Ike insurance claims. In the third quarter of 2008, Enterprise Products Partners’ onshore and offshore facilities located along the Gulf Coast of Texas and Louisiana were adversely impacted by Hurricanes Gustav and Ike. To a lesser extent, these storms affected the operations of TEPPCO as well. The disruptions in natural gas, NGL and crude oil production caused by these storms resulted in decreased volumes for some of Enterprise Products Partners’ pipeline systems, natural gas processing plants, NGL fractionators and offshore platforms, which, in turn, caused a decrease in operating income from these operations. As a result of our allocated share of EPCO’s insurance deductibles for windstorm coverage, Enterprise Products Partners and TEPPCO expensed $47.9 million and $1.0 million, respectively, of repair costs for property damage in connection with these two storms. Enterprise Products Partners’ expects to file property damage insurance claims to the extent repair costs exceed deductible amounts. Due to the recent nature of these storms, Enterprise Products Partners and TEPPCO are still evaluating the total cost of repairs and the potential for business interruption claims on certain assets.

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Proceeds from Business Interruption and Property Damage Claims

The following table summarizes proceeds Enterprise Products Partners received during the periods indicated from business interruption and property damage insurance claims with respect to certain named storms:

	For Year Ended December 31,
	2008		2007		2006
Business interruption proceeds:
Hurricane Ivan	$	--	$	377	$	17,382
Hurricane Katrina		501		19,005		24,500
Hurricane Rita		662		14,955		22,000
Other		--		996		--
Total proceeds		1,163		35,333		63,882
Property damage proceeds:
Hurricane Ivan		--		1,273		24,104
Hurricane Katrina		9,404		79,651		7,500
Hurricane Rita		2,678		24,105		3,000
Other		--		184		--
Total proceeds		12,082		105,213		34,604
Total	$	13,245	$	140,546	$	98,486

At December 31, 2008, Enterprise Products Partners has $39.0 million of estimated property damage claims outstanding related to these storms that we believe are probable of collection through 2009. In February 2009, Enterprise Products Partners collected $20.8 million of the amounts outstanding. To the extent we estimate the dollar value of such damages, please be aware that a change in our estimates may occur as additional information becomes available.

During 2008, we collected $0.2 million of business interruption proceeds that were not related to storm events.

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. We also market natural gas, NGLs, crude oil and other hydrocarbon products. As such, our financial position, results of operations and cash flows may be affected by changes in the commodity prices of these hydrocarbon products, including changes in the relative price levels among these products (e.g., natural gas processing margins are influenced by the ratio of natural gas prices to crude oil prices). The prices of hydrocarbon products are subject to fluctuation 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, processed or stored 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, LPGs, refined products and crude oil handled by our facilities.

A reduction in demand for natural gas, crude oil, NGL and other hydrocarbon 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 such products, (iii) increased competition from other 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, financial position and cash flows.

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Credit Risk due to Industry Concentrations

A substantial portion of our revenues are derived from companies in the domestic natural gas, NGL, crude oil 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 debit agreements with customers that are deemed to be credit risks in order to minimize our potential exposure to any defaults.

Enterprise Products Partners’ largest customer for 2008 was LyondellBassell Industries (“LBI”) and its affiliates, which accounted for 9.6% of Enterprise Products Partners’ consolidated revenues for the year. On January 6, 2009, LBI announced that its U.S. operations had voluntarily filed to reorganize under Chapter 11 of the U.S. Bankruptcy Code. At the time of the bankruptcy filing, Enterprise Products Partners had approximately $17.3 million of credit exposure to LBI, which was reduced to approximately $10.0 million through remedies provided under certain pipeline tariffs. In addition, Enterprise Products Partners is seeking to have LBI accept certain contracts and have filed claims pursuant to current Bankruptcy Court Orders that Enterprise Products Partners expects will allow it to recover the majority of the remaining credit exposure.

Counterparty Risk with respect to Financial Instruments

In those situations 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. Generally, we do not require collateral nor do we anticipate nonperformance by our counterparties.

Note 22. Supplemental Cash Flow Information

We determine net cash flows provided by operating activities using the indirect method, which adjusts net income for items that did not affect cash. Under GAAP, we use the accrual basis of accounting to determine net income. This basis of accounting requires that we record revenue when earned and expenses when incurred. Earned revenues may include credit sales that have not been collected in cash and expenses incurred that may not have been paid in cash. The extent to which changes in operating accounts influence net cash flows provided by operating activities generally depends on the following:

The timing of cash receipts from revenue transactions and cash payments for expense transactions near the end of each reporting period. For example, if significant cash receipts are posted on the last day of the current reporting period, but subsequent payments on expense invoices are made on the first day of the next reporting period, net cash flows provided by operating activities will reflect an increase in the current reporting period that will be reduced as payments are made in the next period. We employ prudent cash management practices and monitor our daily cash requirements to meet our ongoing liquidity needs.

If commodity or other prices increase between reporting periods, changes in accounts receivable and accounts payable and accrued expenses may appear larger than in previous periods; however, overall levels of receivables and payables may still reflect normal ranges. From a receivables standpoint, we monitor the amount of credit extended to customers.

§	Additions to inventory for forward sales transactions or other reasons or increased expenditures for prepaid items would be reflected as a use of cash and reduce overall cash provided by operating activities in a given reporting period. As these assets are charged to expense in

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subsequent periods, the expense amount is reflected as a positive change in operating accounts; however, there is no impact on operating cash flows.

In addition to the adjustments noted above, noncash charges in the income statement are added back to net income and noncash credits are deducted to compute net cash flows provided by operating activities. Examples of noncash charges include depreciation and amortization.

The following table presents adjustments to operating account balances necessary to reconcile net income to net cash flow provided by operating activities (i.e. the net effect of changes in operating assets and liabilities). These amounts are not intended to represent the change in the underlying operating accounts during the periods presented.

	For Year Ended December 31,
	2008			2007			2006
Decrease (increase) in:
Accounts and notes receivable – trade	$	1,333,867		$	(1,176,406	)	$	97,753
Accounts receivable – related parties		191			(179	)		2,558
Inventories		14,923			(34,724	)		(110,448	)
Prepaid and other current assets		(26,268	)		32,634			25,261
Other assets		(12,028	)		(2,128	)		(35,270	)
Increase (decrease) in:
Accounts payable – trade		(7,166	)		42,506			17,805
Accounts payable – related parties		3,351			(4,750	)		(6,961	)
Accrued products payable		(1,720,443	)		1,398,812			40,906
Accrued expenses		4,606			126,463			(68,658	)
Accrued interest		13,930			56,597			22,779
Other current liabilities		(26,659	)		20,376			64,452
Other liabilities		7,072			(1,603	)		(5,901	)
Net effect of changes in operating accounts	$	(414,624	)	$	457,598		$	44,276

Cash payments for interest, net of $90,701, $86,506 and
$66,341 capitalized in 2008, 2007 and 2006, respectively	$	643,037		$	340,508		$	310,199

Cash payments for federal and state income taxes	$	6,777		$	5,760		$	10,497

The following table presents the components of the line item titled “Other” on our Statements of Consolidated Cash Flows for the periods indicated.

	For Year Ended December 31,
	2008			2007		2006
Loss on early extinguishment of debt	$	1,596		$	1,606	$	--
Provision for impairment of long-lived assets		--			--		88
Effect of pension settlement recognition		(114	)		589		--
Unamortized debt issuance costs		--			3,299		--
Changes in value of financial instruments		(926	)		3,307		94
Total other non-cash	$	556		$	8,801	$	182

Accounts payable related to construction-in-progress amounts were as follows at the dates indicated: $108.0 million, December 31, 2008; $98.0 million, December 31, 2007; and $204.6 million, December 31, 2006. 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 Enterprise Products Partners’ projects related to pipeline construction and production well tie-ins. We received $27.3 million, $57.7 million and $60.5 million as contributions in aid of our construction costs during the years ended December 31, 2008, 2007 and 2006, respectively.

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The following table provides supplemental cash flow information regarding business combinations completed during the periods indicated. See Note 13 for additional information regarding our business combination transactions.

	For Year Ended December 31,
	2008			2007			2006
Fair value of assets acquired	$	855,363		$	37,037		$	493,005
Less liabilities assumed		(301,877	)		(1,244	)		(200,803	)
Net assets acquired		553,486			35,793			292,202
Less cash acquired		--			--			--
Cash used for business combinations	$	553,486		$	35,793		$	292,202

In January 2008, TEPPCO incurred $8.7 million of interest expense upon redemption of its 7.51% TE Products Senior Notes. Of the $8.7 million of expense, $6.6 million was a make-whole premium paid upon redemption of the senior notes and $2.1 million represented the write-off of unamortized debt issuance costs and deferred losses on related financial instruments.

In March 2007, TEPPCO sold its 49.5% ownership interest in MB Storage and its general partner and other assets to a third party for approximately $156.0 million in cash. TEPPCO recognized a gain of approximately $73.0 million related to the sale of these equity interests and assets.

In July 2006, Enterprise Products Partners 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. The aggregate value of total consideration Enterprise Products Partners paid or issued to complete the Encinal acquisition was $326.3 million, which consisted of $145.2 million in cash and 7,115,844 of its common units.

Note 23. Quarterly Financial Information (Unaudited)

The following table presents selected quarterly financial data for the years ended December 31, 2008 and 2007:

	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
For the Year Ended December 31, 2008:
Revenues	$	8,506,358	$	10,538,606	$	10,499,136	$	5,925,476
Operating income		479,609		468,802		410,033		416,643
Income before change in accounting principle		46,549		49,367		42,036		26,103
Net income		46,549		49,367		42,036		26,103
Earnings per Unit before change in
accounting principle:
Basic and diluted	$	0.38	$	0.40	$	0.34	$	0.21
Net income per Unit:
Basic and diluted	$	0.38	$	0.40	$	0.34	$	0.21

For the Year Ended December 31, 2007:
Revenues	$	5,340,275	$	6,294,270	$	6,721,724	$	8,357,500
Operating income		281,855		286,047		280,312		345,611
Income before change in accounting principle		53,453		21,504		12,277		21,787
Net income		53,453		21,504		12,277		21,787
Earnings per Unit before change in
accounting principle:
Basic and diluted	$	0.52	$	0.21	$	0.10	$	0.18
Net income per Unit:
Basic and diluted	$	0.52	$	0.21	$	0.10	$	0.18

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Note 24. Supplemental Parent Company Financial Information

In order to fully understand the financial position and results of operations of the Parent Company, we are providing the standalone financial information of Enterprise GP Holdings apart from that of our consolidated partnership financial information.

The Parent Company has no operations apart from its investing activities and indirectly overseeing the management of the entities controlled by it. At December 31, 2008 and 2007, the Parent Company had investments in Enterprise Products Partners, TEPPCO, Energy Transfer Equity and their respective general partners. The Parent Company controls Enterprise Products Partners and TEPPCO through its ownership of EPGP and TEPPCO GP, respectively. The Parent Company owns non-controlling partnership and membership interests in Energy Transfer Equity and LE GP, respectively.

The Parent Company’s primary cash requirements are for general and administrative costs, debt service requirements and distributions to its partners. The principal sources of cash flow for the Parent Company are the distributions it receives from its investments in Enterprise Products Partners, TEPPCO, Energy Transfer Equity and their respective general partners (including associated IDRs). The amount of cash distributions the Parent Company is able to pay its unitholders may fluctuate based on the level of distributions it receives from its investments. For example, if EPO is not able to satisfy certain financial covenants in accordance with its credit agreements, Enterprise Products Partners would be restricted from making quarterly cash distributions to its partners, which includes the Parent Company.

Factors such as capital contributions, debt service requirements, general and administrative costs, reserves for future distributions and other cash reserves established by the Board of EPE Holdings may affect the distributions the Parent Company makes to its unitholders. The Parent Company’s credit facility contains covenants requiring it to maintain certain financial ratios. Also, the Parent Company is prohibited from making any distribution to its unitholders if such distribution would cause an event of default or otherwise violate a covenant under its credit facility.

The Parent Company’s assets and liabilities are not available to satisfy the debts and other obligations of Enterprise Products Partners, TEPPCO, Energy Transfer Equity or their respective general partners. Conversely, the assets and liabilities of these entities are not available to satisfy the debts and obligations of the Parent Company.

Enterprise Products Partners and EPGP

At December 31, 2008, the Parent Company owned 13,670,925 common units of Enterprise Products Partners and 100% of the membership interests of EPGP, which is entitled to 2% of the cash distributions paid by Enterprise Products Partners as well as the IDRs of Enterprise Products Partners.

EPGP’s percentage interest in Enterprise Products Partners’ quarterly cash distributions is increased through its ownership of the associated IDRs, after certain specified target levels of distribution rates are met by Enterprise Products Partners. EPGP’s quarterly general partner and associated incentive distribution thresholds are as follows:

§	2.0% of quarterly cash distributions up to $0.253 per unit paid by Enterprise Products Partners;

§	15.0% of quarterly cash distributions from $0.253 per unit up to $0.3085 per unit paid by Enterprise Products Partners; and

§	25.0% of quarterly cash distributions that exceed $0.3085 per unit paid by Enterprise Products Partners.

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The following table summarizes the distributions received by EPGP from Enterprise Products Partners for the periods indicated:

	For Year Ended December 31,
	2008		2007		2006
From 2% general partner interest	$	18,218	$	16,944	$	15,096
From incentive distribution rights		125,912		107,421		86,710
Total	$	144,130	$	124,365	$	101,806

TEPPCO and TEPPCO GP

Private company affiliates of EPCO (DFI and DFIGP) contributed equity interests in TEPPCO and TEPPCO GP to the Parent Company in May 2007. As a result of such contributions, the Parent Company owns 4,400,000 common units of TEPPCO and 100% of the membership interests of TEPPCO GP, which is entitled to 2% of the cash distributions of TEPPCO as well as the IDRs of TEPPCO. The Parent Company issued 14,173,304 Class B Units and 16,000,000 Class C Units to DFI and DFI GP as consideration for these contributions. In July 2007, all of the outstanding 14,173,304 Class B Units were converted into Units on a one-to-one basis. The Class C Units were converted to Units on February 1, 2009 on a one-to-one basis. See Note 16 for information regarding the Class B and Class C Units.

The contributions of ownership interests in TEPPCO and TEPPCO GP were accounted for at historical costs as a reorganization of entities under common control in a manner similar to a pooling of interests. The following table presents the carryover basis values recorded by the Parent Company at the date of contribution:

4,400,000 common units of TEPPCO	$	148,098
100% membership interest in TEPPCO (including associated IDRs)		591,636
Carryover basis recorded by the Parent Company	$	739,734

The inclusion of TEPPCO and TEPPCO GP in the Parent Company’s financial statements was effective January 1, 2005 because an affiliate of EPCO under common control with the Parent Company originally acquired ownership interests in TEPPCO GP in February 2005. The Parent Company’s financial statements reflect investments in TEPPCO and TEPPCO GP as follows:

Ownership of 100% of the membership interests in TEPPCO GP and associated TEPPCO IDRs for all periods presented. TEPPCO GP is entitled to 2% of the quarterly cash distributions paid by TEPPCO and its percentage interest in TEPPCO’s quarterly cash distributions is increased through its ownership of the associated TEPPCO IDRs, after certain specified target levels of distribution rates are met by TEPPCO. Currently, TEPPCO GP’s quarterly general partner and associated incentive distribution thresholds are as follows:

§	2.0% of quarterly cash distributions up to $0.275 per unit paid by TEPPCO;

§	15.0% of quarterly cash distributions from $0.275 per unit up to $0.325 per unit paid by TEPPCO; and

§	25.0% of quarterly cash distributions that exceed $0.325 per unit paid by TEPPCO.

Prior to December 2006, TEPPCO GP was entitled to 50% of any quarterly cash distributions paid by TEPPCO that exceeded $0.45 per unit. This distribution tier was eliminated by TEPPCO as part of an amendment to its partnership agreement in December 2006 in exchange for the issuance of 14,091,275 common units of TEPPCO to TEPPCO GP, which were subsequently distributed to affiliates of EPCO.

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The economic benefit of the TEPPCO IDRs for periods prior to December 2006 is equal to: (i) the benefit that would have been received by the Parent Company at the current (i.e. post-December 2006) 25.0% maximum threshold assuming historical distribution rates plus (ii) an incremental amount of benefit that would have been received from 4,400,000 of the 14,091,275 common units issued by TEPPCO in December 2006 in connection with the conversion of TEPPCO IDRs in excess of the 25.0% threshold. DFI and DFIGP retain the economic benefit of TEPPCO IDRs associated with the remaining 9,691,275 common units issued by TEPPCO in December 2006. After December 2006, our net income reflects current TEPPCO IDRs (i.e., capped at the 25.0% maximum threshold).

The following table summarizes the distributions received by TEPPCO GP from TEPPCO for the periods indicated:

	For Year Ended December 31,
	2008		2007		2006
From 2% general partner interest	$	5,573	$	5,023	$	4,014
From incentive distribution rights		49,353		43,210		53,946
Total	$	54,926	$	48,233	$	57,960

§	Ownership of 4,400,000 common units of TEPPCO since the date of issuance to affiliates of EPCO in December 2006.

Energy Transfer Equity and LE GP

On May 7, 2007, the Parent Company acquired 38,976,090 common units of Energy Transfer Equity and approximately 34.9% of the membership interests in LE GP for $1.65 billion in cash. On January 22, 2009, the Parent Company acquired an additional 5.7% membership interest in LE GP for $0.8 million, which increased our total ownership in LE GP to 40.6%.

LE GP owns a 0.31% general partner interest in Energy Transfer Equity, which general partner interest has no associated IDRs in the quarterly cash distributions of Energy Transfer Equity. The business purpose of LE GP is to manage the affairs and operations of Energy Transfer Equity. LE GP has no separate business activities outside of those conducted by Energy Transfer Equity.

Energy Transfer Equity is a publicly traded Delaware limited partnership formed in 2002 that completed its initial public offering in February 2006. Energy Transfer Equity’s only cash generating assets are its direct and indirect investments in limited partner interests of ETP and membership interests in ETP’s general partner. Energy Transfer Equity owns common units of ETP and the general partner of ETP, which is entitled to 2% of the quarterly cash distributions of ETP as well as the associated ETP IDRs. Currently, the general partner of ETP receives quarterly cash distributions from ETP representing the general partner share and associated ETP IDRs as follows:

§	2.0% of quarterly cash distributions up to $0.275 per unit paid by ETP;

§	15.0% of quarterly cash distributions from $0.275 per unit up to $0.3175 per unit paid by ETP;

§	25.0% of quarterly cash distributions from $0.3175 per unit up to $0.4125 per unit paid by ETP; and

§	50.0% of quarterly cash distributions that exceed $0.4125 per unit paid by ETP.

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Parent Company Cash Flow Information

The following table presents the Parent Company’s cash flow information for the periods indicated:

	For Year Ended December 31,
	2008			2007			2006
Operating activities:
Net income	$	164,055		$	109,021		$	133,992
Adjustments to reconcile net income to net cash
flows provided by operating activities:
Amortization		1,330			9,723			365
Equity in earnings of unconsolidated affiliates		(238,777	)		(187,540	)		(145,587	)
Cash distributions from investees		313,506			237,595			182,008
Change in accounting principle		--			--			(18	)
Net effect of changes in operating accounts		(5,342	)		15,874			(4,637	)
Net cash flows provided by operating activities		234,772			184,673			166,123
Investing activities:
Investments		(7,735	)		(1,650,827	)		(18,920	)
Cash used in investing activities		(7,735	)		(1,650,827	)		(18,920	)
Financing activities:
Borrowings under debt agreements		67,615			3,787,000			41,000
Repayments of debt		(80,615	)		(2,852,000	)		(20,500	)
Debt issuance costs		(58	)		(18,629	)		(1,019	)
Cash distributions paid by Parent Company		(213,143	)		(159,042	)		(108,449	)
Proceeds from issuance of Parent Company’s Units, net		--			739,458			--
Cash distributions paid by former owners of TEPPCO interests		--			(29,760	)		(57,960	)
Contribution from partners		24			--			--
Cash provided by (used in) financing activities		(226,177	)		1,467,027			(146,928	)
Net change in cash and cash equivalents		860			873			275
Cash and cash equivalents, January 1		1,656			783			508
Cash and cash equivalents, December 31	$	2,516		$	1,656		$	783

Equity earnings represent the Parent Company’s share of the total net income of Enterprise Products Partners, TEPPCO, Energy Transfer Equity and their respective general partners. The amounts the Parent Company records as equity earnings differs from the cash distributions it receives since net income includes non-cash amounts such as depreciation and amortization expense. In addition, cash distributions may also be impacted by the maintenance of cash reserves by each underlying entity and other provisions.

In August 2007, the Parent Company executed its $1.20 billion August 2007 Credit Agreement, which refinanced amounts due under a short-term interim credit facility used to finance the acquisition of equity interests in Energy Transfer Equity and LE GP in May 2007. In November 2007, the Parent Company executed its $850.0 million Term Loan B, the net proceeds of which were used to refinance a short-term obligation under the August 2007 Credit Agreement. See Note 15 for additional information regarding the Parent Company’s debt obligations.

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The following table details the components of cash distributions received from investees and cash distributions paid by the Parent Company for the periods indicated:

	For Year Ended December 31,
	2008		2007		2006
Cash distributions from investees: (1)
Investment in Enterprise Products Partners and EPGP:
From common units of Enterprise Products Partners (2)	$	27,514	$	25,766	$	24,150
From 2% general partner interest in Enterprise Products Partners		18,219		16,944		15,096
From general partner IDRs in distributions of
Enterprise Products Partners		123,855		104,652		84,802
Investment in TEPPCO and TEPPCO GP:
From 4,400,000 common units of TEPPCO		12,496		12,056		10,869
From 2% general partner interest in TEPPCO		5,573		5,023		4,014
From general partner IDRs in distributions of TEPPCO		49,353		43,210		43,077
Investment in Energy Transfer Equity and LE GP: (3)
From 38,976,090 common units of Energy Transfer Equity		76,004		29,720		--
From 34.9% member interest in LE GP		492		224		--
Total cash distributions received	$	313,506	$	237,595	$	182,008

Distributions by the Parent Company:
EPCO and affiliates	$	158,947	$	125,875	$	93,910
Public		54,175		33,153		14,528
General partner interest		21		14		11
Total distributions by the Parent Company (4)	$	213,143	$	159,042	$	108,449

Distributions paid to affiliates of EPCO that were the former
owners of the TEPPCO and TEPPCO GP interests contributed
to the Parent Company in May 2007 (5)	$	--	$	29,760	$	57,960

(1) Represents cash distributions received during each reporting period. (2) Prior to November 2008, the Parent Company owned 13,454,498 common units of Enterprise Products Partners. In November 2008, the Parent Company used $5.0 million in distributions received from Enterprise Products Partners with respect to the third quarter of 2008 to purchase an additional 216,427 common units. As of December 31, 2008, the Parent Company owned 13,670,925 common units of Enterprise Products Partners. (3) The Parent Company received its first cash distribution from Energy Transfer Equity and LE GP in July 2007. (4) The quarterly cash distributions paid by the Parent Company increased effective with the August 2007 distribution due to the issuance of 20,134,220 Units in July 2007. See Note 16 for information regarding this equity offering. (5) Represents cash distributions paid to affiliates of EPCO that were former owners of these partnership and membership interests prior to the contribution of such interests to the Parent Company in May 2007.

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Parent Company Balance Sheet Information

The following table presents the Parent Company’s balance sheet information at the dates indicated:

	December 31,
	2008		2007
ASSETS
Current assets	$	4,649	$	6,444
Investments:
Enterprise Products Partners and EPGP		829,145		823,168
TEPPCO and TEPPCO GP		708,535		734,891
Energy Transfer Equity and LE GP		1,564,025		1,619,097
Total investments		3,101,705		3,177,156
Other assets		8,163		9,974
Total assets	$	3,114,517	$	3,193,574

LIABILITIES AND PARTNERS’ EQUITY
Current liabilities	$	23,185	$	20,208
Long-term debt (see Note 15)		1,077,000		1,090,000
Other long-term liabilities		13,242		9,967
Partners’ equity		2,001,090		2,073,399
Total liabilities and partners’ equity	$	3,114,517	$	3,193,574

To the extent that the Parent Company’s investments in Enterprise Products Partners, EPGP, TEPPCO and TEPPCO GP are equal to the underlying capital accounts of the Parent Company in each entity, the investment balances are eliminated in the process of preparing our general purpose consolidated financial statements.

At December 31, 2008, the Parent Company’s aggregate investment in TEPPCO and TEPPCO GP included $809.8 million of excess cost amounts consisting of $606.9 million attributed to IDRs (an indefinite-life intangible asset), $197.6 million of goodwill, $0.4 million of customer relations for intangible assets and $4.9 million attributed to fixed assets. These excess cost amounts have been reclassified to the appropriate balance sheet line items in preparing our general purpose consolidated financial statements. See Note 14 for additional information regarding the intangible assets and goodwill amounts we recorded in connection with the receipt of the TEPPCO and TEPPCO GP interests in May 2007.

Long-term debt represents amounts borrowed under the Parent Company’s credit facility (see Note 15). Debt principal outstanding at December 31, 2008 and 2007 includes $1.1 billion borrowed in connection with the acquisition of ownership interests in Energy Transfer Equity and LE GP (see Note 15).

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Parent Company Income Information

The following table presents the Parent Company’s income information for the periods indicated:


	For Year Ended December 31,
	2008			2007			2006
Equity earnings:
Enterprise Products Partners and EPGP	$	167,767		$	128,471		$	111,093
TEPPCO and TEPPCO GP		39,712			55,974			34,494
Energy Transfer Equity and LE GP		31,298			3,095			--
Total equity earnings		238,777			187,540			145,587
General and administrative costs		7,283			4,299			2,116
Operating income		231,494			183,241			143,471
Other income (expense):
Interest expense		(67,495	)		(74,432	)		(9,547	)
Interest income		57			212			50
Total		(67,438	)		(74,220	)		(9,497	)
Provision for income tax		(1	)		--			--
Income before cumulative effect of change
in accounting principle		164,055			109,021			133,974
Cumulative effect of change in
accounting principle		--			--			18
Net income	$	164,055		$	109,021		$	133,992

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