Exhibit 99.2

Risk Factors.

An investment in our common 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 common units could decline and you could lose part or all of your investment.

The following section lists the key current risk factors as of the date of this filing that may have a direct and material impact on our business, financial position, results of operations and cash flows.

Risks Relating to Our Business

Our operating cash flow is derived primarily from cash distributions we receive from EPO (including cash flow from Energy Transfer Equity).

Our operating cash flow is derived primarily from cash distributions we receive from EPO (including cash flow Energy Transfer Equity). As discussed further below, the amount of cash that EPO and Energy Transfer Equity can distribute each quarter principally depends upon the amount of cash flow it generates from its operations, which will fluctuate from quarter to quarter based on, among other things, the:

·   volume of hydrocarbon products 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 various storage, terminaling, processing and transportation services;

·   price of natural gas, crude oil and NGLs;

·   relationships among natural gas, crude oil 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

·   level of competition in its business segments and market areas.

In addition, the actual amount of cash EPO and Energy Transfer Equity will have available for distribution will depend on other factors, including:

·   the level of sustaining capital expenditures incurred;

·   its cash outlays for capital projects and acquisitions;

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

·   the amount of cash reserves required by us and LE GP for the normal conduct of EPO’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, we and Energy Transfer Equity may not have sufficient available cash each quarter to continue paying distributions at our and their current levels. Furthermore, the amount of cash that each of we and Energy Transfer Equity has available for cash distribution depends primarily upon our and 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, each of Energy Transfer Equity and us may be able to make cash distributions during periods when we respectively record losses and may not be able to make cash distributions during periods when we respectively record net income.

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See below for a discussion of further risks affecting our ability to generate distributable cash flow.  These risks also generally apply to Energy Transfer Equity as they operate in our industry.

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

We 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, our financial position, results of operations and cash flows may be materially adversely affected by changes in the prices of hydrocarbon products and by changes in the relative price levels among hydrocarbon products.  Changes in prices may impact demand for hydrocarbon products, which in turn may impact production, demand and volumes of product for which we provide services.  We may also incur credit and price risk to the extent counterparties do not perform in connection with our marketing of natural gas, NGLs, propylene, refined products and/or crude oil.

Historically, the price of natural gas has been extremely volatile, and we expect this volatility to continue.  The New York Mercantile Exchange (“NYMEX”) daily settlement price for natural gas for the prompt month contract in 2008 ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu.  In 2009, the same index ranged from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu.  From January 1, 2010 through September 30, 2010, the same index ranged from a high of $6.01 per MMBtu to a low of $3.65 per MMBtu.

Generally, the prices of hydrocarbon products are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional uncontrollable factors.  Some of these factors include:

·   the level of domestic production and consumer product demand;

·   the availability of imported oil and natural gas and actions taken by foreign oil and natural gas producing nations;

·   the availability of transportation systems with adequate capacity;

·   the availability of competitive fuels;

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

·   the impact of conservation efforts;

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

·   the overall economic environment.

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

With respect to our Petrochemical & Refined Products Services segment, market demand and our revenues from these businesses can also be adversely affected by different end uses of the products we transport, market or store.  For example:

·   demand for gasoline depends upon market price, prevailing economic conditions, demographic changes in the markets we serve and availability of gasoline produced in refineries located in these markets;

·   demand for distillates is affected by truck and railroad freight, the price of natural gas used by utilities that use distillates as a substitute and usage for agricultural operations;

·   demand for jet fuel depends on prevailing economic conditions and military usage; and

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·   propane deliveries are generally sensitive to the weather and meaningful year-to-year variances have occurred and will likely continue to occur.

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

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

The crude oil, natural gas and NGLs currently transported, gathered or processed at our facilities originate from existing domestic and international resource basins, which naturally deplete over time.  To offset this natural decline, our facilities will need access to production from newly discovered properties.  Many economic and business factors are beyond our control and can adversely affect the decision by producers to explore for and develop new reserves.  These factors could include relatively low oil and natural gas prices, cost and availability of equipment and labor, regulatory changes, capital budget limitations, the lack of available capital or the probability of success in finding hydrocarbons.  A decrease in exploration and development activities in the regions where our facilities and other energy logistic assets are located could result in a decrease in volumes to our offshore platforms, natural gas processing plants, natural gas, crude oil and NGL pipelines, and NGL fractionators, which would have a material adverse affect on our financial position, results of operations and cash flows.  

In addition, imported liquefied natural gas (“LNG”) may become a significant component of future natural gas supply to the United States.  Much of this increase in LNG supplies may be imported through new LNG facilities that have currently been developed or new LNG facilities that have been announced to be developed over the next decade.  We cannot predict which, if any, of these announced, but as yet unbuilt, projects will be constructed.  In addition, anticipated increases in future natural gas supplies may not be made available to our facilities and pipelines if (i) a significant number of these new projects fail to be developed with their announced capacity, (ii) there are significant delays in such development, (iii) they are built in locations where they are not connected to our assets or (iv) they do not influence sources of supply on our systems.  If the expected increase in natural gas supply through imported LNG is not realized, projected natural gas throughput on our pipelines would decline, which could have a material adverse effect on our financial position, results of operations and cash flows.

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

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

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

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

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

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

We face competition from third parties in our midstream businesses.

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

Our refined products, NGL and marine transportation businesses compete with other pipelines and marine transportation companies in the areas they serve.  We also compete with trucks and railroads in some of the areas we serve.  Substantial new construction of inland marine vessels could create an oversupply and intensify competition for our marine transportation business.  Competitive pressures may adversely affect our tariff rates or volumes shipped.

The crude oil gathering and marketing business can be characterized by thin operating 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.  Our crude oil transportation business competes with common carriers and proprietary pipelines owned and operated by major oil companies, large independent pipeline companies, financial institutions with trading platforms and other companies in the areas where such pipeline systems deliver crude oil and NGLs.

In our natural gas gathering business, we encounter competition in obtaining contracts to gather natural gas supplies, particularly new supplies.  Competition in natural gas gathering is based in large part on reputation, efficiency, system reliability, gathering system capacity and price arrangements.  Our key competitors in the gas gathering segment include independent gas gatherers and major integrated energy companies.  Alternate gathering facilities are available to producers we serve, and those producers may also elect to construct proprietary gas gathering systems.  If production delivered to our gathering system declines, our revenues from such operations will decline.

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

As of December 31, 2009, we had approximately $10.85 billion principal amount of consolidated senior long-term debt outstanding and approximately $1.53 billion principal amount of junior subordinated debt outstanding.  This amount includes (i) $1.1 billion of debt we incurred in the Holdings merger through the refinancing of Holdings’ revolving credit facility and term loans with additional borrowings under EPO’s revolving credit facility, (ii) $1.95 billion of new EPO notes issued in connection with the TEPPCO merger (exchanged for TEPPCO’s previously tendered notes) and (iii) $457.3 million outstanding under Duncan Energy Partners’ revolving credit facility and term loan.  In addition, at September 30, 2010, we had approximately $13.7 billion principal amount of consolidated debt, which includes the $1.1 billion of debt we incurred in the Holdings merger. The amount of our future debt could have significant effects on our operations, including, among other things:

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

·   credit rating agencies may view our consolidated debt level negatively;

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

·   our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

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

·   we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.

Our public debt indentures currently do not limit the amount of future indebtedness that we can create, incur, assume or guarantee.  Although our credit agreements restrict our ability to incur additional debt above certain levels, any debt we may incur in compliance with these restrictions may still be substantial.  For information regarding our credit facilities, see Note 12 of the Notes to Consolidated Financial Statements included in our annual report on Form 10-K for the year ended December 31, 2009 as originally filed on March 1, 2010 and our unaudited pro forma condensed consolidated financial statements included under Exhibit 99.1 of our current report on Form 8-K filed on November 9, 2010.

Our credit agreements and each of our indentures for our public debt contain conventional financial covenants and other restrictions.  For example, we are prohibited from making distributions to our partners if such distributions would cause an event of default or otherwise violate a covenant under our credit agreements.  A breach of any of these restrictions by us could permit our lenders or noteholders, as applicable, to declare all amounts outstanding under these debt agreements to be immediately due and payable and, in the case of our credit agreements, to terminate all commitments to extend further credit.

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

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

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

We will require substantial new capital to finance the future development and acquisition of assets and businesses.  Any limitations on our access to capital may impair our ability to execute this growth strategy.  If our cost of debt or equity capital becomes too expensive, our ability to develop or acquire accretive assets will be limited.  We also may not be able to raise necessary funds on satisfactory terms, if at all.  

Tightening of the credit markets in the future may have a material adverse effect on us by, among other things, decreasing our ability to finance expansion projects or business acquisitions on favorable terms and by the

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imposition of increasingly restrictive borrowing covenants.  In addition, the distribution yields of new equity issued may be at a higher yield than our historical levels, making additional equity issuances more expensive.

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

Our variable-rate debt and future maturities of fixed-rate, long-term debt make us vulnerable to increases in interest rates, which could materially adversely affect our business, financial position, results of operation and cash flows.

As of December 31, 2009, we had outstanding $12.4 billion principal amount of consolidated debt, which includes $1.1 billion of debt we incurred in the Holdings merger through the refinancing of Holdings’ revolving credit facility and term loans with additional borrowings under EPO’s revolving credit facility.  Of this amount, approximately $2.2 billion, or 17.5%, was subject to variable interest rates, either as long-term variable-rate debt obligations or as long-term fixed-rate debt converted to variable rates through the use of interest rate swaps.   We have $54.0 million of 8.70% fixed-rate debt that matured on March 1, 2010, and $500.0 million of 4.95% fixed-rate senior notes that matured in June 2010.  In 2011, 2012 and 2013, we have $450.0 million, $1.0 billion and $1.2 billion, respectively, of senior notes maturing.  In addition, our $1.75 billion revolving credit facility matures in 2012 and Duncan Energy Partners’ revolving credit facility and term loan totaling $582.3 million mature in 2011.

As of September 30, 2010, we had outstanding $13.7 billion principal amount of consolidated debt, which includes $1.1 billion of debt we incurred in the Holdings merger.  Of this amount, approximately $1.7 billion, or 12.1%, was subject to variable interest rates, either as short-term or long-term variable rate debt obligations or as long-term fixed-rate debt converted to variable rates through the use of interest rate swaps.

The rate on our June 2009 issuance of $500.0 million of Senior Notes due August 2012 was 4.6%.  The rate on our September 2009 issuance of $500.0 million of Senior Notes due 2020 was 5.25%, and the rate on our September 2009 issuance of $600.0 million of Senior Notes due 2039 was 6.125%.  The rate on our May 2010 issuance of $400.0 million of Senior Notes due 2015 was 3.70%, the rate on our May 2010 issuance of $1,100.0 million of Senior Notes due 2020 was 5.20%, and the rate on our May 2010 issuance of $600.0 million of Senior Notes due 2040 was 6.45%.  Should interest rates increase significantly, the amount of cash required to service our debt would increase.  As a result, our financial position, results of operations and cash flows, could be materially adversely affected.

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 common units.  Any such reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.

Operating cash flows from our capital projects may not be immediate.

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

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

Our growth strategy includes making accretive acquisitions.  As a result, from time to time, we will evaluate and acquire assets and businesses (either ourselves or Duncan Energy Partners may do so) that we believe complement our existing operations.  We may be unable to successfully integrate and manage businesses we acquire in the future.  We may incur substantial expenses or encounter delays or other problems in connection with our growth strategy that could negatively impact our 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 that we are required to maintain under the Sarbanes-Oxley Act of 2002;

·   managing relationships with new joint venture partners with whom we have not previously partnered;

·   experiencing unforeseen operational interruptions or the loss of key employees, customers or suppliers;

·   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, amortization and accretion expenses.  As a result, our capitalization and results of operations may change significantly following an acquisition.  A substantial increase in our indebtedness and contingent liabilities could have a material adverse effect on our 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.

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

Even if we make acquisitions that we believe will increase our cash from operations, these acquisitions may nevertheless reduce our cash from operations on a per unit basis.  Any acquisition involves assumptions that may not materialize and potential risks that may occur.  These risks include our inability to achieve our operating and financial projections or to integrate an acquired business successfully, the assumption of unknown liabilities for which we become liable, and the loss of key employees or key customers.

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

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

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

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shortages of skilled labor and additional expenses for these construction and development projects, as were experienced with Hurricanes Gustav and Ike in 2008. 

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

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

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

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

·   we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize;

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

·   where we do rely on third-party estimates of reserves in making a decision to construct facilities, these estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating reserves;

·   the completion or success of our project may depend on the completion of a project that we do not control, such as a refinery, that may be subject to numerous of its own potential risks, delays and complexities; and

·   we may be unable to obtain rights-of-way to construct additional pipelines or the cost to do so may be uneconomical.

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

A significant amount of our common units and all of our Class B units that are owned by EPCO and certain of 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 could ultimately result.

An affiliate of EPCO has pledged a significant amount of its common units and all of its Class B units in us as security under its credit facility.  This credit facility contains customary and other events of default relating to defaults of the borrower and certain of its affiliates, including us.  An event of default, followed by a foreclosure on the pledged collateral, could ultimately result in a change in ownership of us.  

The credit and risk profile of our general partner, its owners and their affiliates could adversely affect our risk profile, which could increase our borrowing costs, hinder our ability to raise capital or impact future credit ratings.

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

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Affiliates of the entities controlling the owner of our general partner have significant indebtedness outstanding and are dependent principally on the cash distributions from their limited partner equity interests in us to service such indebtedness.  Any distributions by us to such entities will be made only after satisfying our then current obligations to creditors.

Although we have taken certain steps in our organizational structure, financial reporting and contractual relationships to reflect the separateness of us and our general partner from the entities that control our general partner, our credit ratings and business risk profile could be adversely affected if the ratings and risk profiles of EPCO or the entities that control our general partner were viewed as substantially lower or more risky than ours.

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

We are a holding company with no business operations, and our operating subsidiaries conduct all of our operations and own all of our operating assets.  Our only significant assets are the ownership interests we own in our operating subsidiary, EPO.  As a result, we depend upon the earnings and cash flow of EPO and its subsidiaries and joint ventures and the distribution of that cash to us in order to meet our obligations and to allow us to make cash distributions to our partners.  The ability of EPO and its subsidiaries and joint ventures to make cash distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC policies.  For example, all cash flows from Evangeline are currently used to service its debt.

As of December 31, 2009, EPO also owned 33,783,587 common units of Duncan Energy Partners, representing approximately 58.6% of its outstanding common units and 100% of its general partner.   As of September 30, 2010, EPO owned common units of Duncan Energy Partners representing approximately 58.5% of its outstanding limited partner units and 100% of its general partner.  EPO also owned noncontrolling interests in subsidiaries of Duncan Energy Partners that held total assets of approximately $4.8 billion and $5.3 billion as of December 31, 2009 and September 30, 2010, respectively.  With respect to three subsidiaries of Duncan Energy Partners acquired from us on December 8, 2008 that held approximately $3.7 billion and $3.8 billion of total assets as of December 31, 2009 and September 30, 2010, respectively, Duncan Energy Partners has effective priority rights to specified quarterly distribution amounts ahead of distributions on our retained equity interests in these subsidiaries.

In addition, the charter documents governing EPO’s joint ventures typically allow their respective joint venture management committees sole discretion regarding the occurrence and amount of distributions.  Three of the joint ventures in which EPO 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 cash distributions to us under certain circumstances.  Accordingly, EPO’s joint ventures may be unable to make cash distributions to us at current levels, if at all.

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

We participate in several joint ventures.  Due to the nature of some of these arrangements, each participant in these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of that joint venture.  These participation and protective features customarily include a corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100%) to authorize more significant activities.  Examples of these more significant activities are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital, transactions with affiliates of a joint venture participant, litigation and transactions not in the ordinary course of business, among others.  Thus, without the concurrence of joint venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of us or the particular joint venture.

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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 us being required to partner with different or additional parties.

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

Some of our operations involve risks of personal injury, property damage and environmental damage, which could curtail our operations and otherwise materially adversely affect our cash flow.  For example, natural gas facilities operate at high pressures, sometimes in excess of 1,100 lbs per square inch.  We also operate crude oil and natural gas facilities located underwater in the Gulf of Mexico, which can involve complexities, such as extreme water pressure.  In addition, our marine transportation business is subject to additional risks, including the possibility of marine accidents and spill events.    From time to time, our octane enhancement facility may produce MTBE for export, which could expose us to additional risks from spill events.  Virtually all of our operations are exposed to potential natural disasters, including hurricanes, tornadoes, storms, floods and/or earthquakes.  The location of our assets and our customers’ assets in the U.S. Gulf Coast region makes them particularly vulnerable to hurricane risk.

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

We believe that EPCO maintains adequate insurance coverage on our behalf, although insurance will not cover many types of interruptions that might occur, will not cover amounts up to applicable deductibles and will not cover all risks associated with certain of our products.  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 us to obtain certain types of coverage.  As a result, EPCO may not be able to renew existing insurance policies on behalf of us or procure other desirable insurance on commercially reasonable terms, if at all.  If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our financial position, 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 if such an event were to occur.

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

At December 31, 2009, our balance sheet reflected $2.02 billion of goodwill and $1.06 billion of intangible assets.  At September 30, 2010, our balance sheet reflected $2.05 billion of goodwill and $1.86 billion of intangible assets.  Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets.  Generally accepted accounting principles in the United States (“GAAP”) require us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired.  Long-lived assets such as intangible assets with finite useful lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.  If we determine that any of our goodwill or intangible assets were impaired, we would be required to take an immediate charge to earnings with a correlative effect on partners’ equity and balance sheet leverage as measured by debt to total capitalization.

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

We historically have sought to limit a portion of the adverse effects resulting from changes in energy commodity prices and interest rates by using financial derivative instruments and other hedging mechanisms from time to time.  To the extent that we hedge our commodity price and interest rate exposures, we will forego the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor.  In addition, even though monitored by management, hedging activities can result in losses.  Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is imperfect, or hedging policies and procedures are not followed.  Adverse economic conditions, such as the financial crisis that developed in the fourth quarter of 2008 and continued into 2009, increase the risk of nonpayment or performance by our hedging counterparties.  See Note 6 of the Notes to Supplemental Consolidated Financial Statements included under Exhibit 99.3 of this current report on Form 8-K for a discussion of our derivative instruments.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

Risks of nonpayment and nonperformance by customers are a major consideration in our businesses, and our credit procedures and policies may not be adequate to sufficiently eliminate customer credit risk.  Further, adverse economic conditions, such as the credit crisis that developed in the fourth quarter of 2008 and continued into 2009, increase the risk of nonpayment and nonperformance by customers, particularly for customers that are smaller companies.  We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments, net out agreements and guarantees.  However, these procedures and policies do not fully eliminate customer credit risk.

Our primary market areas are located in the Gulf Coast, Southwest, Rocky Mountain, Northeast and Midwest regions of the United States.  We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers.  These concentrations of market areas may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors.  Our consolidated revenues are derived from a wide customer base.  During 2009, our largest non-affiliated customer based on revenues was Shell, which accounted for 9.8% of our revenues.  During 2008 and 2007, our largest non-affiliated customer based on revenues was Valero, which accounted for 11.2% and 8.9%, respectively, of our revenues.

Our risk management policies cannot eliminate all commodity price risks.  In addition, any non-compliance with our risk management policies could result in significant financial losses.

To enhance utilization of certain assets and our operating income, we purchase petroleum products.  Generally, it is our policy to maintain a position that is substantially balanced between purchases, on the one hand, and sales or future delivery obligations, on the other hand.  Through these transactions, we seek to establish a margin for the commodity purchased by selling the same commodity for physical delivery to third-party users, such as producers, wholesalers, independent refiners, marketing companies or major oil companies.  These policies and practices cannot, however, eliminate all price risks.  For example, any event that disrupts our anticipated physical supply could expose us to risk of loss resulting from price changes if we are required to obtain alternative supplies to cover these transactions.  We are also exposed to basis risks when a commodity is purchased against one pricing index and sold against a different index.  Moreover, we are exposed to some risks that are not hedged, including price risks on product inventory, such as pipeline linefill, which must be maintained in order to facilitate transportation of the commodity on our pipelines.  In addition, our marketing operations involve the risk of non-compliance with our risk management policies.  We cannot assure you that our processes and procedures will detect and prevent all violations of our risk management policies, particularly if deception or other intentional misconduct is involved.

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Our pipeline integrity program and periodic tank maintenance requirements may impose significant costs and liabilities on us.

The DOT 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 HCAs.  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 majority of the costs to comply with this integrity management rule are associated with pipeline integrity testing and any repairs found to be necessary as a result of such testing.  Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline’s integrity and changes to the amount of pipe determined to be located in HCAs can have a significant impact on the costs to perform integrity testing and repairs.  We will continue our pipeline integrity testing programs to assess and maintain the integrity of our pipelines.  The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

In June 2008, the DOT issued a Final Rule extending its pipeline safety regulations, including integrity management requirements, to certain rural onshore hazardous liquid gathering lines and certain rural onshore low-stress hazardous liquid pipelines within a buffer area around “unusually sensitive areas.”  The issuance of these new gathering and low-stress pipeline safety regulations, including requirements for integrity management of those pipelines, is likely to increase the operating costs of our pipelines subject to such new requirements.

The American Petroleum Institute Standard 653 ( “API 653”) is an industry standard for the inspection, repair, alteration and reconstruction of existing storage tanks. API 653 requires regularly scheduled inspection and repair of tanks remaining in service.  Periodic tank maintenance requirements could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our storage tanks.

Additional regulations that cause delays or deter new offshore oil and gas drilling could have a material adverse effect on our financial position, results of operations and cash flows.

On April 20, 2010, the Deepwater Horizon drilling rig caught fire and sank in the Gulf of Mexico, resulting in an oil spill that has significantly impacted ecological resources in the Gulf of Mexico.  As a result, on May 28, 2010, the U.S. Department of the Interior issued a six-month moratorium that halted drilling of uncompleted and new oil and gas wells (in water deeper than 500 feet) in the Gulf of Mexico with certain limited exceptions and halted consideration of drilling permits for deepwater wells.  In addition to the moratorium, the Department of the Interior also canceled or delayed offshore oil and gas lease sales off the Mid-Atlantic coast and in Alaska.  Under political and legal pressure, the Interior Secretary withdrew the moratorium and replaced it on July 12, 2010 with a suspension of certain offshore drilling activities that was to be effective through October 30, 2010.

The drilling suspension was lifted by the Interior Secretary on October 12, 2010.  However, the timing and process for approving applications for new permits to drill and the cost associated with compliance with various new and enhanced safety and environmental requirements imposed following the Deepwater Horizon incident (discussed below) remain uncertain.

Following the Deepwater Horizon event, the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOEMRE”), formerly the Minerals Management Service, an office of the Department of the Interior which is charged with oversight of the United States’ oil, natural gas and other minerals on the Outer Continental Shelf, is being reorganized under a secretarial order of the Department of the Interior, which may be reinforced through legislation.  Since the Deepwater Horizon event, the Department of the Interior, through the BOEMRE, has issued a series of rules that increase regulatory requirements for offshore oil and gas operations.  On June 8, 2010, the BOEMRE issued a notice to holders of offshore oil and gas leases requiring compliance certifications and third party verification of certain inspection and design matters.  On June 18, 2010, a subsequent notice to lessees called for enhanced information regarding planning scenarios relating to blowouts, discharges of pollutants and prevention

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of accidents.  Another notice to lessees on August 16, 2010, made changes to the environmental review process for offshore oil and gas development.  On October 14, 2010, the BOEMRE published an emergency drilling safety rule imposing additional requirements for well bore integrity and well control equipment and procedures, including provisions addressing blowout preventers and the use of drilling fluids.  This interim final rule became effective immediately, but is subject to future changes that may be made by the BOEMRE in response to public comments received by December 13, 2010.  On October 15, 2010, the BOEMRE also published a final rule requiring safety and environmental management systems for all oil and gas operations on the Outer Continental Shelf.  The Interior Secretary has stated that companies with offshore operations will face a “dynamic regulatory environment” following the end of the moratorium and suspension.  Moreover, understaffing at the Department of the Interior and reorganization of the BOEMRE may further delay the processing of permits.  In addition to federal regulatory activity, at least one state has ordered enhanced inspections of oil and gas rigs and required more stringent disaster preparedness plans, and it is possible that other state-level requirements will be imposed on offshore energy production activities.

Accordingly, the effect of new regulatory requirements on offshore energy development in the Gulf of Mexico, including the prospects and timing of securing permits for offshore energy production activities, are evolving and uncertain.  Such uncertainty may cause companies to curtail or delay oil and gas production activities, or to redirect resources to other areas such as West Africa, the Caribbean or South America, which may further delay the resumption of drilling activity in the Gulf of Mexico.  It is uncertain at this time how and to what extent oil and natural gas supplies from the Gulf of Mexico and other offshore drilling areas will be affected.

In addition to federal agency action, numerous legislative proposals have been introduced in the U.S. Congress in reaction to the Deepwater Horizon incident, some of which may be considered during the remainder of the current legislative session, and similar measures may be introduced in subsequent legislative periods.  Bills that have received attention include measures to:

·   modify or revoke liability limits and caps under the Oil Spill Liability Trust Fund, the Oil Pollution Act of 1990, and certain other statutes;

·   revise federal liability regimes to include health effects, personal injuries, and other tort claims; 

·   mandate more stringent safety measures and inspections under the Oil Pollution Act and Outer Continental Shelf Lands Act;

·   expand environmental reviews and lengthen review timelines; 

·   impose fees, increase taxes or remove tax exemptions;

·   modify financial responsibility and insurance requirements for offshore energy activities; and

·   require U.S. registration of oil rigs.

However, it is unclear and cannot be predicted whether and when Congress may pass legislation.

Given the scope and effect of the Deepwater Horizon incident to date, as well as statements made by the Interior Secretary, it is expected that additional regulatory compliance and agency review will be required prior to permitting new wells or continued drilling of existing wells, which may affect the cost and timing of oil and gas production in the Gulf of Mexico and other offshore areas.  A decline in, or failure to achieve anticipated volumes of, oil and natural gas supplies due to any of the foregoing factors may have a material adverse effect on our financial position, results of operations or cash flows through reduced gathering and transportation volumes, processing activities, or other midstream services.

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

Our operations are subject to extensive federal, state and local regulatory requirements relating to environmental affairs, health and safety, waste management and chemical and petroleum products.  Further, we cannot ensure that existing environmental regulations will not be revised or that new regulations, such as regulations

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designed to reduce the emissions of greenhouse gases, will not be adopted or become applicable to us.  Governmental authorities have the power to enforce compliance with applicable regulations and permits and to subject violators to civil and criminal penalties, including substantial fines, injunctions or both.  Certain environmental laws, including CERCLA and analogous state laws and regulations, impose strict, joint and several liability for costs required to cleanup and restore sites where hazardous substances or hydrocarbons have been disposed or otherwise released.  Moreover, third parties, including neighboring landowners, may also have the right to pursue legal actions to enforce compliance or to recover for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

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

Climate change regulation is one area of potential future environmental law development.  Certain 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.  

On December 7, 2009, the EPA announced its findings that emissions of “greenhouse gases” present an endangerment to human health and the environment.  These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA.  In late September 2009, the EPA had proposed two sets of CAA regulations in anticipation of finalizing its endangerment findings that would require a reduction in emissions of greenhouse gases from motor vehicles and, also, could trigger permit review for greenhouse gas emissions from certain stationary sources.  In addition, on September 22, 2009, the EPA issued a final CAA rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010.  These regulations will require reporting for some of our facilities, and additional EPA regulations expected to be adopted in 2010 will require other of our facilities to report their greenhouse gas emissions, possibly beginning in 2012 for emissions occurring in 2011.

Also, on June 26, 2009, the U.S. House of Representatives passed the ACESA, which would establish an economy-wide cap-and-trade program intended to reduce U.S. emissions of “greenhouse gases.” ACESA would require a 17% reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050.  Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere.  The cost of these allowances would be expected to escalate significantly over time.  The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas.  The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support of legislation to reduce greenhouse gas emissions through an emission allowance system.

Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, the adoption and implementation of any CAA regulations, and any future federal, state or local laws or implementing regulations that may be adopted to address greenhouse gas emissions, could require us to incur increased operating costs and could adversely affect demand for the crude oil, natural gas and other hydrocarbon products that we transport, store or otherwise handle in connection with our midstream services.  The effect on our operations could include increased costs to operate and maintain our facilities, measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.  While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain and may depend on events

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beyond our control, including the outcome of future rate proceedings before the FERC and the provisions of any final legislation.

Additionally, proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used in fracturing fluids by the oil and natural gas industry under the federal Safe Drinking Water Act (“SDWA”) and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, Emergency Planning and Community Right-to-Know Act, or other authority.  Hydraulic fracturing is an important and commonly used process in the completion of unconventional oil and natural gas wells in shale, coal bed and tight sand formations.  Sponsors of these bills have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts.  The Chairman of the House Energy and Commerce Committee has initiated an investigation of the potential impacts of hydraulic fracturing, which has involved seeking information about fracturing activities and chemicals from certain companies in the oil and gas sector.  In addition, in March 2010, the U.S. EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health.  The EPA has begun preparation for the study and expects to complete the study in 2012.  In addition, various state-level initiatives in regions with substantial shale gas supplies have been proposed or implemented to regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, or protect drinking water supplies.  Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas, particularly in the Marcellus Shale play.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques.  Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, incurred by our customers or could make it more difficult to perform hydraulic fracturing.  If these legislative and regulatory initiatives cause a material decrease in the drilling of new wells and related servicing activities, our profitability could be materially impacted.

Our marine transportation operations are also subject to state and local laws and regulations that control the discharge of pollutants into the environment or otherwise relate to environmental protection.  Compliance with such laws, regulations and standards may require installation of costly equipment or operational changes.  Failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our marine operations.  Some environmental laws often impose strict liability for remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault.  Under the OPA, owners, operators and bareboat charterers are jointly and severally strictly liable for the discharge of oil within the internal and territorial waters of, and the 200-mile exclusive economic zone around, the United States.  Additionally, an oil spill from one of our vessels could result in significant liability, including fines, penalties, criminal liability and costs for natural resource damages.  The potential for these releases could increase if we increase our fleet capacity.  In addition, most states bordering on a navigable waterway have enacted legislation providing for potentially unlimited liability for the discharge of pollutants within their waters.

Global warming, if occurring, may also impact our operations directly, including increased maintenance costs for our facilities, increased flooding and severe weather risks for our facilities that are located in low-lying areas and coastal regions, and reduced demand for hydrocarbon products that may reduce demand and volumes of the products that we process, transport, market and store. 

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

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

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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.  The FERC requires that our services are provided on a non-discriminatory basis so that all shippers have open access to our pipelines and storage.  Pursuant to the FERC’s jurisdiction over interstate gas pipeline rates, existing pipeline rates may be challenged by customer complaint or by the FERC and proposed rate increases may be challenged by protest.

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

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

Although our natural gas gathering systems are generally exempt from FERC regulation under the NGA, FERC regulation still significantly affects our 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 we are able to charge in the future.  In addition, our 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 or if the states in which we operate adopt policies imposing more onerous regulation on gathering.  Additional rules and legislation pertaining to these matters are considered and adopted from time to time at both state and federal levels.  We cannot predict what effect, if any, such regulatory changes and legislation might have on our operations, but we could be required to incur additional capital expenditures.

Increasingly stringent federal, state and local laws and regulations governing worker health and safety and the manning, construction and operation of marine vessels may significantly affect our marine transportation operations.  Many aspects of the marine industry are subject to extensive governmental regulation by the USCG, the DOT, the Department of Homeland Security, the National Transportation Safety Board and the U.S. Customs and Border Protection, and to regulation by private industry organizations such as the ABS.  The USCG and the National Transportation Safety Board set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards.  The USCG is authorized to inspect vessels at will.

For a general overview of federal, state and local regulation applicable to our assets, see “Regulation” included within Items 1 and 2 of our annual report on Form 10-K for the year ended December 31, 2009 as originally filed on March 1, 2010.  This regulatory oversight can affect certain aspects of our business and the market for our products and could materially adversely affect our cash flows.

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

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

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The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

The United States Congress has passed, and the President has signed into law, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”). The Act provides for new statutory and regulatory requirements for financial derivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on exchanges, and cash collateral will be required for these transactions. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and to the parties to those transactions. The Act requires the Commodity Futures Trading Commission (the “CFTC”) to promulgate rules to define these terms in detail, but we do not know the definitions that the CFTC will actually promulgate or how these definitions will apply to us.

The majority of our financial derivative transactions are currently executed and cleared over exchanges that already require the posting of cash collateral or letters of credit based on initial and variation margin requirements.  We enter into over-the-counter natural gas, NGL, crude oil and refined products derivative contracts from time to time with respect to a portion of our expected processing, storage and transportation activities in order to hedge against commodity price uncertainty and enhance the predictability of cash flows from these activities.  Depending on the rules and definitions adopted by the CFTC, we might in the future be required to provide additional cash collateral for our commodities hedging transactions whether cleared over an exchange or new cash collateral for those transactions executed over-the-counter.  Posting of additional or new cash collateral could cause liquidity issues for us by reducing our ability to use our cash for capital expenditures or other partnership purposes.  A requirement to post additional or new cash collateral could therefore significantly reduce our ability to execute strategic hedges to reduce commodity price uncertainty and thus protect cash flows.  We are at risk unless and until the CFTC adopts rules and definitions that confirm that companies such as ourselves are not required to post cash collateral for our over-the-counter derivative hedging contracts not increase the amount of cash collateral posted for transactions cleared over an exchange.  In addition, even if we ourselves are not required to post cash collateral for our derivative contracts, the banks and other derivatives dealers who are our contractual counterparties will be required to comply with the Act’s new requirements, and the costs of their compliance will likely be passed on to customers such as ourselves, thus decreasing the benefits to us of hedging transactions and reducing our profitability.

Our rates are subject to review and possible adjustment by federal and state regulators, which could have a material adverse effect on our financial condition and results of operations.

The FERC, pursuant to the ICA, as amended, the Energy Policy Act and rules and orders promulgated thereunder, regulates the tariff rates for our interstate common carrier pipeline operations.  To be lawful under the ICA, interstate tariff rates, terms and conditions of service must be just and reasonable and not unduly discriminatory, and must be on file with the FERC.  In addition, pipelines may not confer any undue preference upon any shipper.  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 can also challenge tariff rates that have become final and effective.  The FERC also can order reparations for overcharges effective two years prior to the date of a complaint.  Due to the complexity of rate making, the lawfulness of any rate is never assured.  A successful challenge of our rates could adversely affect our revenues.

The FERC uses prescribed rate methodologies for approving regulated tariff rates for interstate liquids pipelines.   The FERC’s indexing methodology currently allows a pipeline to increase its rates by a percentage linked to the producer price index for finished goods.  As an alternative to using the indexing methodology, interstate liquids pipelines may elect to support rate filings by using a cost-of-service methodology, Market-Based Rates or agreements with all of the pipeline’s shippers that the rate is acceptable.  These methodologies may limit our ability to set rates based on our actual costs or may delay the use of rates reflecting increased costs.  Changes in the FERC’s approved methodology for approving rates, or challenges to our application of that methodology, could

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adversely affect us.  Adverse decisions by the FERC in approving our regulated rates could adversely affect our cash flow.

The intrastate liquids pipeline transportation services we provide are subject to various state laws and regulations that apply to the rates we charge and the terms and conditions of the services we offer.  Although state regulation typically is less onerous than FERC regulation, the rates we charge and the provision of our services may be subject to challenge.

Our partnership status may be a disadvantage to us in calculating our cost of service for rate-making purposes.

In May 2005, the FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass through partnership entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income.  The policy statement also provides that 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.  In December 2005, the FERC issued its first significant case-specific review of the income tax allowance issue in another pipeline partnership’s rate case.  The FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance.  The new tax allowance policy and the December 16, 2005 order were appealed to the United States Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”).The D.C. Circuit denied these appeals in May 2007 and fully upheld the FERC’s new tax allowance policy and the application of that policy in the December 2005 order.

In December 2006, the FERC issued a new order addressing rates on another pipeline.  In the new order, FERC refined its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships.  It noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which the FERC characterized as a “tax savings.”  The FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers.  Responding to this concern, the FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income.

In April 2008, the FERC issued a Policy Statement in which it declared that it would permit master limited partnerships (“MLPs”) to be included in rate of return proxy groups for determining rates for services by natural gas and oil pipelines.  It also addressed the application to limited partnership pipelines of the FERC’s discounted cash flow methodology for determining rates of return on equity.  The FERC applied the new policy to several ongoing proceedings involving other pipelines.  The FERC’s rate of return policy remains subject to change.

The ultimate outcome of these proceedings is not certain and could result in changes to the FERC’s treatment of income tax allowances in cost of service as well as rates of return, particularly with respect to pipelines organized as partnerships.  The outcome of these ongoing proceedings could adversely affect our revenues for any of our rates that are calculated using cost of service rate methodologies.

Our marine transportation business would be adversely affected if we failed to comply with the Jones Act provisions on coastwise trade, or if those provisions were modified, repealed or waived.

We are subject to the Jones Act and other federal laws that restrict maritime transportation between points in the United States to vessels built and registered in the United States and owned and manned by U.S. citizens.  We are responsible for monitoring the ownership of our common units and other partnership interests.  If we do not comply with these restrictions, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines or forfeiture of the vessels.

In the past, interest groups have lobbied Congress to repeal the Jones Act to facilitate foreign flag competition for trades and cargoes currently reserved for U.S.-flag vessels under the Jones Act and cargo preference

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laws.  We believe that interest groups may continue efforts to modify or repeal the Jones Act and cargo preference laws currently benefiting U.S.-flag vessels.  If these efforts are successful, it could result in increased competition, which could reduce our revenues and cash available for distribution.

The Secretary of the Department of Homeland Security is vested with the authority and discretion to waive the coastwise laws to such extent and upon such terms as he may prescribe whenever he deems that such action is necessary in the interest of national defense.  For example, in response to the effects of Hurricanes Katrina and Rita, the Secretary of the Department of Homeland Security waived the coastwise laws generally for the transportation of petroleum products from September 1 to September 19, 2005 and from September 26, 2005 to October 24, 2005.  In the past, the Secretary of the Department of Homeland Security has waived the coastwise laws generally for the transportation of petroleum released from the Strategic Petroleum Reserve undertaken in response to circumstances arising from major natural disasters.  Any waiver of the coastwise laws, whether in response to natural disasters or otherwise, could result in increased competition from foreign marine vessel operators, which could reduce our revenues and cash available for distribution.

We depend on the leadership and involvement of key personnel for the success of our businesses.

We depend on the leadership, involvement and services of key personnel.  The loss of leadership and involvement or the services of certain 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 securities.

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 and employees allocate their time among us, EPCO and other affiliates of EPCO.  These officers and employees face potential conflicts regarding the allocation of their time, which may adversely affect our business, results of operations and financial condition.

We have entered into an ASA that governs business opportunities among entities controlled by EPCO, which includes us and our general partner and Duncan Energy Partners and its general partner.  For detailed information regarding how business opportunities are handled within the EPCO group of companies, see Item 13 in our annual report on Form 10-K for the year ended December 31, 2009 as originally filed on March 1, 2010.

We do not have a separate 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.  For a discussion of our executive compensation policies and procedures, see Item 11 in our annual report on Form 10-K for the year ended December 31, 2009 as originally filed on March 1, 2010.

The global financial crisis and its ongoing effects may have impacts on our business and financial condition that we currently cannot predict.

We may face significant challenges if conditions in the financial markets revert to those that existed in the fourth quarter of 2008 and during 2009.  Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to do so, which could have an adverse impact on our 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 our lenders or customers, causing them to fail to meet their obligations to us.  Additionally, demand for our services and products 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 the petrochemical and refining industries due to a decrease in demand for their products as a result of general economic conditions would likely impact demand for our services and products.  Any of these factors could

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lead to reduced usage of our pipelines and energy logistics services, which could have a material negative impact on our revenues and prospects.

Risks Relating to Our Partnership Structure

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

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

·   the ownership interest of a unitholder immediately prior to the issuance will decrease;

·   the amount of cash available for distributions on each common unit may decrease;

·   the ratio of taxable income to distributions may increase;

·   the relative voting strength of each previously outstanding common unit may be diminished; and

·   the market price of our common units may decline.

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

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

·   the volume of the products that we handle and the prices we receive for our services;

·   the level of our operating costs;

·   the level of competition in our business segments and marketing areas;

·   prevailing economic conditions, including the price of and demand for oil, natural gas and other products we transport, store and market;

·   the level of capital expenditures we make;

·   the amount and cost of capital we can raise compared to the amount of our capital expenditures and debt maturities;

·   the restrictions contained in our debt agreements and our debt service requirements;

·   fluctuations in our working capital needs;

·   the weather in our operating areas;

·   cash outlays for acquisitions, if any; and

·   the amount, if any, of cash reserves required by our general partner in its sole discretion.

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

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

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

Cost reimbursements and fees due to EPCO and its affiliates, including our general partner may be substantial and will reduce our cash available for distribution to holders of our units.

Prior to making any distribution on our units, we will reimburse EPCO and its affiliates, including officers and directors of our general partner, for all expenses they incur on our behalf, including allocated overhead.  These amounts will include all costs incurred in managing and operating us, including costs for rendering administrative staff and support services to us, and overhead allocated to us by EPCO.  The payment of these amounts could adversely affect our ability to pay cash distributions to holders of our units.  EPCO has sole discretion to determine the amount of these expenses.  In addition, EPCO and its affiliates may provide other services to us for which we will be charged fees as determined by EPCO.

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

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

·   neither our partnership agreement nor any other agreement requires our general partner or EPCO to pursue a business strategy that favors us;

·   decisions of our general partner regarding the amount and timing of asset purchases and sales, cash expenditures, borrowings, issuances of additional units and reserves in any quarter may affect the level of cash available to pay quarterly distributions to unitholders and our general partner;

·   under our partnership agreement, our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

·   Our general partner is allowed to resolve any conflicts of interest involving us and our general partner and its affiliates;

·   Our general partner is allowed to take into account the interests of parties other than us, such as EPCO, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to unitholders;

·   any resolution of a conflict of interest by our general partner not made in bad faith and that is fair and reasonable to us shall be binding on the partners and shall not be a breach of our partnership agreement;

·   affiliates of our general partner may compete with us in certain circumstances;

·   Our general partner has limited its liability and reduced its fiduciary duties and has also restricted the remedies available to our unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty.  As a result of purchasing our units, you are deemed to consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

·   we do not have any employees and we rely solely on employees of EPCO and its affiliates;

·   in some instances, our general partner may cause us to borrow funds in order to permit the payment of distributions;

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·   our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

·   Our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, may be entitled to be indemnified by us;

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

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

We have significant business relationships with entities controlled by EPCO and Dan Duncan LLC.  For detailed information on these relationships and related transactions with these entities, see Item 13 of our annual report on Form 10-K for the year ended December 31, 2009 as originally filed on March 1, 2010.

Unitholders have limited voting rights and are not entitled to elect our general partner or its directors, which could lower the trading price of our common units.  In addition, even if unitholders are dissatisfied, they cannot easily remove our general partner.

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

Furthermore, if unitholders are dissatisfied with the performance of our general partner, they currently have no practical ability to remove our general partner or its officers or directors.  Our general partner may not be removed except upon the vote of the holders of at least 60% of our outstanding units voting together as a single class.  Because affiliates of our general partner own approximately 31% of our outstanding common units after giving effect to the merger on November 22, 2010, the removal of our general partner is highly unlikely without the consent of both our general partner and its affiliates.  As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership because of the absence or reduction of a takeover premium in the trading price.

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

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

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

If at any time our general partner and its affiliates own 85% or more of the common units then outstanding, 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 remaining common units held by unaffiliated persons at a price not less than the then current market price.  As a result, common unitholders may be required to sell their common units at an undesirable time or price and may therefore not receive any return on their investment.  They may also incur a tax liability upon a sale of their units.

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

Under Delaware law, common unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.  Under Delaware law, our general partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those of our contractual obligations that are expressly made without recourse to our general partner.

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

·   we were conducting business in a state, but had not complied with that particular state’s partnership statute; or

·   your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business.

Unitholders may have liability to repay distributions.

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

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

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

Risks Related to Our Ownership of Energy Transfer Equity and Affiliates

We may have to take actions that are disruptive to its 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

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securities.  Registration as an investment company would subject us to restrictions that are inconsistent with its 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 noncontrolling equity interests in 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 (e.g., Duncan Energy Partners), 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 Duncan Energy Partners 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 SEC, 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 would 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 common units.

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 indirect ownership of 100% of the incentive distribution rights (“IDRs”) in ETP, 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.   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 ETP 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 its ownership interest in the IDRs in ETP as compared to cash distributions Energy Transfer Equity receives from ETP on its general partner interest in ETP (representing a 1.9% and a 1.8% interest as of December 31, 2009 and September 30, 2010, respectively) 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.

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Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states.  If the Internal Revenue Service were to treat us as a corporation or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our common unitholders would be substantially reduced.

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

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

Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to a material amount of entity level taxation.  In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to enhance state-tax collections.  If any additional state were to impose an entity-level tax upon us or our operating subsidiaries, the cash available for distribution to our common unitholders would be reduced.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time.  Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception, which we refer to as the qualifying income exception, for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, 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 or adversely affect an investment in our common units.  For example, in response to recent public offerings of interests in the management operations of private equity funds and hedge funds, members of Congress are considering substantive changes to the definition of qualifying income under Section 7704 of the Internal Revenue Code and changing the treatment of certain types of income earned from profits or “carried” interests.  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.  Although we are unable to predict whether any of these changes or other proposals will ultimately be enacted, and if so, whether any such changes would be applied retroactively, the enactment of any such changes could negatively impact the value of an investment in our common units.

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of 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 challenge this method or new Treasury Regulations are issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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

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

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

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

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

Investments in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons, raise issues unique to them.  For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.  Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

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

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

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

In addition to federal income taxes, our common unitholders will likely be subject to other taxes, including state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property.  Our common unitholders will likely

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be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions.  Further, they may be subject to penalties for failure to comply with those requirements.  We may own property or conduct business in other states or foreign countries in the future.  It is the responsibility of each unitholder to file its own federal, state and local tax returns.

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

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

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

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

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders.  It also could affect the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns without the benefit of additional deductions.

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units.  If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a common unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and he may recognize gain or loss from such disposition.  Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.  Our counsel has not rendered an opinion regarding the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

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