RISK FACTORS

An investment in our securities involves a high degree of risk. You should carefully consider the following risk factors included below, together with all of the other information included in, or incorporated by reference into, this prospectus in evaluating an investment in our securities. If any of these risks were to occur, our business, financial condition or results of operations could be adversely affected. In that case, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Inherent in an Investment in Us

Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.

The amount of cash we can distribute on our common units or other partnership securities depends upon the amount of cash we generate from our operations. The amount of cash we generate from our operations will fluctuate from quarter to quarter and will depend upon, among other things:

In addition, the actual amount of cash available for distribution will also depend on other factors, such as:

Because of all these factors, we cannot guarantee that we will have sufficient available cash to pay a specific level of cash distributions to our unitholders.

Furthermore, you should be aware that the amount of cash we have available for distribution depends primarily upon our 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. As a result, we may make cash distributions during periods when we record net losses and may not make cash distributions during periods when we record net income.

3

Table of Contents

We may sell additional limited partner interests, diluting existing interests of unitholders.

Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the common units, without the approval of the unitholders. The issuance of additional common units or other equity securities will have the following effects:

Future sales of our units or other limited partner interests in the trading market could reduce the market price of unitholders’ limited partner interests.

As of May 31, 2006, Energy Transfer Equity, L.P., which we refer to as “ETE” in this prospectus (formerly La Grange Energy, L.P.), owned 33,843,690 common units and 2,570,150 class F units, which may be converted to common units. ETE owns our general partner. If ETE were to sell and/or distribute its common units to the holders of its equity interests in the future, those holders may dispose of some or all of these units. The sale or disposition of a substantial portion of these units in the trading markets could reduce the market price of our outstanding common units.

On July 10. 2006, we announced that a special meeting of our common unitholders will be held at 10:00 a.m. Central Daylight Time on August 15, 2006 to consider and approve of the conversion of our class F units into common units. The record date for determining the holders of common units entitled to vote at the special meeting was July 20, 2006.

Our increased debt level and debt agreements may limit our ability to make distributions to unitholders and our future financial and operating flexibility.

As of May 31, 2006, we had approximately $2.1 billion of consolidated debt outstanding on a pro forma basis after giving effect to the acquisition of Titan, including the incurrence of additional borrowings related to the acquisition of Titan, which indebtedness represented approximately 50% of our total book capitalization as of that date on a pro forma basis. Our indebtedness consists of $750.0 million in principal amount of 5.95% Senior Notes due 2015, $400.0 million in principal amount of 5.65% Senior Notes due 2012 and a Revolving Credit Facility that allows for borrowings of up to $1.3 billion, which is expandable to $1.5 billion, through June 29, 2011. We also maintain separate credit facilities for HOLP. The terms of our indebtedness and our operating partnerships, ETC, OLP and HOLP, (which are collectively referred to as the “Operating Partnerships” in this prospectus), are described in more detail below. Our level of indebtedness affects our operations in several ways, including, among other things:

4

Table of Contents

Senior Notes

On January 18, 2005, in a Rule 144A private placement offering, we issued $750.0 million in aggregate principal amount of 5.95% Senior Notes due on February 1, 2015, which we refer to as the “2015 Unregistered Notes” in this prospectus. We recorded a discount of $2.2 million and debt issue costs of $7.4 million in connection with the issuance of the 2015 Unregistered Notes. The net proceeds of approximately $741.0 million were used to repay the indebtedness and accrued interest outstanding under the then existing credit facilities that were previously secured by the assets of ETC OLP. On July 29, 2005, we completed the exchange of the 2015 Unregistered Notes for substantially similar notes registered under the Securities Act of 1933, as amended.

On July 29, 2005, in a Rule 144A private placement offering, we issued $400.0 million in aggregate principal amount of 5.65% Senior Notes due on August 1, 2012, which we refer to as the “2012 Unregistered Notes” in this prospectus and together with the 2015 Unregistered Notes, the “ETP Senior Notes.” We recorded a discount of $0.4 million in connection with the issuance of the 2012 Unregistered Notes. The net proceeds of approximately $397.1 million from the sale of the 2012 Unregistered Notes were used to retire a portion of our outstanding indebtedness under our revolving credit facility, to fund capital expansion projects and for general partnership purposes. We commenced an offer to exchange the 2012 Unregistered Notes for substantially similar registered notes, which closed on March 31, 2006. All $400.0 million of Unregistered Notes were tendered and were replaced with a like amount of substantially similar registered notes.

The ETP Senior Notes represent senior unsecured obligations of Energy Transfer Partners, L.P. and rank equally with all of our other existing and future unsecured and unsubordinated indebtedness. The ETP Senior Notes are jointly and severally guaranteed by ETC OLP and all of the direct and indirect wholly-owned and majority-owned subsidiaries of ETC OLP. The subsidiary guarantees rank equally in right of payment with all of the existing and future unsubordinated indebtedness of our guarantor subsidiaries. The ETP Senior Notes and each guarantee will effectively rank junior to any future indebtedness of ours or our subsidiary guarantors that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP Senior Notes will effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries that are not subsidiary guarantors.

The ETP Senior Notes were issued under an indenture containing covenants, which include covenants that restrict our ability to, subject to certain exceptions, incur debt secured by liens, engage in sale and leaseback transactions or merge or consolidate with another entity or sell substantially all of our assets.

Revolving Credit Facility

On December 13, 2005, we entered into the ETP Revolving Credit Facility, a $900 million five-year revolving credit facility available through December 13, 2010 which replaced our previous revolving credit facility. The ETP Revolving Credit Facility was amended as of June 29, 2006 to increase the facility to 1.3 billion, which is expandable to $1.5 billion, and extended the maturity date to June 29, 2011. Amounts borrowed under the ETP Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The maximum commitment fee payable on the unused portion of the facility is 0.175%.

The ETP Revolving Credit Facility requires that, on the last day of each of our fiscal quarters, the ratio of our Consolidated Funded Debt (as defined in the credit agreement relating to the ETP Revolving Credit Facility) to our Consolidated EBITDA (as defined in the credit agreement relating to the ETP Revolving Credit Facility)

5

Table of Contents

for the four fiscal quarters most recently ended must be no greater than 4.75 to 1.00 except that, on the last day of any fiscal quarter in which we or our subsidiaries makes an acquisition with a purchase price of $50.0 million or more such ratio must be no greater than 5.25 to 1.0. You should note that our Consolidated Debt to our Consolidated EBITDA for purposes of our financial covenants includes only our operations and our Restricted Subsidiaries’ operations and exclude our operations and those of our subsidiaries that are not Restricted Subsidiaries. In addition, this facility requires that the ratio of our Consolidated EBITDA (as defined in the credit agreement relating to the ETP Revolving Credit Facility) to our Consolidated Interest Expense (as defined in the credit agreement relating to the ETP Revolving Credit Facility) for the four fiscal quarters most recently ended must not be less than 3.0 to 1.0. We satisfied our leverage ratio covenants for the fiscal year ended August 31, 2005 and for the three months ended May 31, 2006 and therefore were able to make the cash distributions at the levels we distributed during these periods.

On May 31, 2006, we entered into a $250.0 million Revolving Credit Facility (the “Short-Term Revolving Facility”) which matures on December 1, 2006. Amounts borrowed under this facility will bear interest at a rate based on either a Eurodollar rate or a base rate. There were no amounts outstanding on this facility as of May 31, 2006. The proceeds are intended to be used for working capital purposes. The maximum commitment fee payable on the unused portion of the facility is 0.25%. The Short-Term Revolving Facility is fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP. The Short-Term Revolving Facility is unsecured and has equal rights to holders of our other current and future unsecured debt. On July 3, 2006, we reduced our borrowing capacity on the Short-Term Revolving Facility to $200.0 million. All terms, and maturity date, as mentioned above remain unchanged.

ETC OLP and its designated subsidiaries act as guarantors of the debt obligations under the ETP Revolving Credit Facility and the Short-Term Revolving Facility. If we were to default on the ETP Revolving Credit Facility or the Short-Term Revolving Facility, ETC OLP and its designated subsidiaries would be responsible for full repayment of our debt obligations under the ETP Revolving Credit Facility or the Short-Term Revolving Facility, as applicable. The ETP Revolving Credit Facility and the Short-Term Revolving Facility are unsecured and the lenders thereunder have equal rights to holders of our other current and future unsecured senior debt.

HOLP Facilities

Working Capital Facility . Effective March 31, 2004, HOLP entered into the Third Amended and Restated Credit Agreement, which includes a $75.0 million senior revolving working capital facility available through December 31, 2006, which we refer to as the “HOLP Working Capital Facility” in this prospectus. Amounts borrowed under the working capital facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 5.308% for the amount outstanding at August 31, 2005. HOLP must reduce the principal amount of working capital borrowings to $10.0 million for a period of not less than 30 consecutive days at least one time during each fiscal year. HOLP completed the 30-day clean down requirement under the HOLP Working Capital Facility during the third quarter ended May 31, 2006. All receivables, contracts, equipment (other than vehicles), inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the HOLP Working Capital Facility. A $5.0 million Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the HOLP Working Capital Facility. As of May 31, 2006, the HOLP Working Capital Facility did not have a balance outstanding. There were outstanding Letters of Credit for the HOLP Working Capital Facility of $6.1 million at May 31, 2006. Letter of Credit Exposure plus the Working Capital Loan cannot exceed the $75.0 million maximum Working Capital Facility. In no event may our Letter of Credit exposure under the HOLP Working Capital Facility exceed $15.0 million at any one time.

Prior to May 31, 2006, HOLP also maintained a $75.0 million Senior Revolving Acquisition Facility, which we refer to as the “HOLP Acquisition Facility” in this prospectus. During the second quarter of fiscal year 2006, HOLP paid in full the outstanding indebtedness under the HOLP Acquisition Facility and canceled the facility.

6

Table of Contents

Senior Secured Notes . In connection with our initial public offering, on June 25, 1996, HOLP entered into a Note Purchase Agreement whereby HOLP issued $120 million principal amount of 8.55% Senior Secured Notes, which we refer to as the “HOLP Notes” in this prospectus, with institutional investors. Interest is payable semi-annually in arrears on each December 31 and June 30. The HOLP Notes have a final maturity of June 30, 2011, with ten equal mandatory repayments of principal, which began on June 30, 2002. At May 31, 2006, $72 million of principal debt was outstanding under the HOLP Notes.

On November 19, 1997, HOLP entered into a Note Purchase Agreement that provided for the issuance of up to $100 million of senior secured promissory notes, which we refer to as “HOLP Medium Term Note Program” in this prospectus, if certain conditions were met. An initial placement of $32 million (Series A and B), at an average interest rate of 7.23% with an average 10-year maturity, was completed at the closing of the HOLP Medium Term Note Program. Interest is payable semi-annually in arrears on each November 19 and May 19. An additional placement of $15 million (Series C, D and E), at an average interest rate of 6.59% with an average 12-year maturity, was completed in March 1998. Interest is payable on Series C semi-annually in arrears on each September 13 and March 13. The proceeds of the placements were used to refinance amounts outstanding under the HOLP Acquisition Facility. No future placements are permitted under the unused portion of the HOLP Medium Term Note Program. During the fiscal year ended August 31, 2003, $3.9 million and $5.0 million of the proceeds from the issuance of 1,610,000 of Common Units were used to retire the balance of the Series D and Series E Senior Secured Notes, respectively. At May 31, 2006, $24.0 million of principal debt was outstanding under the HOLP Medium Term Note Program.

On August 10, 2000, HOLP entered into a Note Purchase Agreement, which we refer to as “HOLP Senior Secured Promissory Notes” in this prospectus, that provided for the issuance of up to $250 million of fixed rate senior secured promissory notes if certain conditions were met. An initial placement of $180 million (Series A through F) at an average rate of 8.66% with an average 13-year maturity was completed in conjunction with the merger with U.S. Propane. Interest is payable quarterly. The proceeds were used to finance the transaction with U.S. Propane and retire a portion of existing debt. On May 24, 2001, HOLP issued an additional $70 million (Series G through I) of the Senior Secured Promissory Notes to a group of institutional lenders with 7-, 12- and 15-year maturities and an average coupon rate of 7.66%. HOLP used the net proceeds from the Senior Secured Promissory Notes to repay the balance outstanding under the HOLP Acquisition Facility and to reduce other debt. Interest is payable quarterly. During the fiscal year ended August 31, 2003, HOLP used $7.5 million and $19.5 million of the proceeds from the issuance of 1,610,000 of common units to retire a portion of the Series G and Series H Senior Secured Promissory Notes, respectively. At May 31, 2006, $192.1 million of principal debt was outstanding under the HOLP Senior Secured Promissory Notes.

Covenants Related to HOLP Credit Agreements . The Note Agreements for each of the HOLP Notes, the HOLP Medium Term Note Program and the HOLP Senior Secured Promissory Notes, and HOLP Working Capital Facility contain customary restrictive covenants applicable to HOLP, changes in ownership of HOLP, including limitations on the level of additional indebtedness, creation of liens, and substantial disposition of assets. These covenants require HOLP to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as defined in the Note Purchase Agreements of HOLP) of not more than 4.75 to 1.00 and Consolidated EBITDA to Consolidated Interest Expense (as defined in the Note Purchase Agreements of HOLP) of not less than 2.25 to 1. For purposes of calculating the ratios under the Note Purchase Agreements of HOLP, Consolidated EBITDA is based upon the HOLP’s EBITDA, as adjusted, during the most recent four quarterly periods and modified to give pro forma effect for acquisitions and divestures made during the test period, and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. The Note Purchase Agreements also provide that HOLP may declare, make, or incur a liability to make, a restricted payment during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash (As defined in the Note Purchase Agreements of HOLP) with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payment; and (c) HOLP’s restricted payments are not greater than the product of HOLP’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as

7

Table of Contents

defined in the Note Purchase Agreements). The Note Purchase Agreements further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the HOLP Notes. In addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, Available Cash is required to reflect a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.

Failure to comply with the various restrictive and affirmative covenants of HOLP Working Capital Facility and the Note Agreements could negatively impact our ability to incur additional debt and our ability to pay distributions. We are required to measure these financial tests and covenants quarterly and were in compliance with all financial requirements, tests, limitations, and covenants related to financial ratios under the Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and the Working Capital Facility at May 31, 2006. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the Senior Secured, Medium Term, and Senior Secured Promissory Notes. In addition to the stated interest rate for the Notes, we are required to pay an additional 1% per annum on the outstanding balance of the Notes at such time as the Notes are not rated investment grade status or higher. Since April 18, 2004, the Notes have rated investment grade or better thereby alleviating the requirement that we pay the additional 1% interest.

The general partner is not elected by the unitholders and cannot be removed without its consent.

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 and will have no right to elect our general partner on an annual or other continuing basis. Although our general partner has a fiduciary duty to manage us in a manner beneficial to Energy Transfer Partners, L.P. and the unitholders, the directors of our general partner and its general partner, Energy Transfer Partners, L.L.C., have a fiduciary duty to manage the general partner and its general partner in a manner beneficial to the owners of those entities.

Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The general partner generally may not be removed except upon the vote of the holders of 66  ² / 3 % of the outstanding units voting together as a single class, including units owned by the general partner and its affiliates. Prior to any sales or distributions pursuant to this prospectus, ETE and its affiliates held approximately 33% of all the units, with an approximately 2% of units held by our officers and directors. Consequently, it could be difficult to remove the general partner without the consent of the general partner and our affiliates.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner and its affiliates, cannot be voted on any matter.

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

The general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the general partner of our general partner from transferring its general partner interest in our general partner to a third party. Any new owner of the general partner would be in a position to replace the officers of the general partner with its own choices and to control the decisions taken by such officers.

Unitholders may be required to sell their units to the general partner at an undesirable time or price.

If at any time less than 20% of the outstanding units of any class are held by persons other than the general partner and its affiliates, the general partner will have the right to acquire all, but not less than all, of those units

8

Table of Contents

at a price no less than their then-current market price. As a consequence, a unitholder may be required to sell his common units at an undesirable time or price. The general partner may assign this purchase right to any of its affiliates or to us.

Cost reimbursements due our general partner may be substantial and reduce our ability to pay the distributions to unitholders.

Prior to making any distributions on the units, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by the general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to the unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees.

Unitholders may have liability to repay distributions.

Under certain circumstances unitholders may have to repay us amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to you if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non- recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.

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

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that reduce the obligations to which our general partner would otherwise be held by state-law fiduciary duty standards. The following is a summary of the material restrictions contained in our partnership agreement on the fiduciary duties owed by our general partner to the limited partners. Our partnership agreement:

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

9

Table of Contents

The general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.

Our partnership agreement requires the general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.

Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its own interests to the detriment of unitholders.

Prior to any sales or distributions pursuant to this prospectus, ETE and its affiliates directly and indirectly owned an aggregate limited partner interest of approximately 33% and our officers and directors owned approximately 2% of the limited partner interests in us. Conflicts of interest could arise in the future as a result of relationships between our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts our general partner may favor its own interests and those of its affiliates over the interests of the unitholders. The nature of these conflicts includes the following considerations:

Risks Related to our Business

The profitability of our midstream, transportation and storage business is largely dependent upon natural gas commodity prices, price spreads between two or more physical locations and market demand for natural gas and NGLs, which are factors beyond our control and have been volatile.

Income from our midstream, transportation and storage business is exposed to risks due to fluctuations in commodity prices. For a portion of the natural gas gathered at the Southeast Texas System, we purchase natural gas from producers at the wellhead at a price that is at a discount to a specified index price and then gather and

10

Table of Contents

deliver the natural gas to pipelines where we typically resell the natural gas at the index price. Generally, the gross margins we realize under these discount-to-index arrangements decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price.

For a portion of the natural gas gathered at the Southeast Texas System, we enter into percentage-of- proceeds arrangements and keep-whole arrangements, pursuant to which we agree to gather and process natural gas received from the producers. Under percentage-of-proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements our revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have an adverse effect on our results of operations. Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, our revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs if we are not able to bypass our processing plants and sell the unprocessed natural gas.

In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, during our fiscal year ended August 31, 2005, the New York Mercantile Exchange, or NYMEX, settlement price for the prior month contract ranged from a high of $7.98 per MMBtu to a low of $5.08 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon our average NGLs composition during our fiscal year ended August 31, 2005 ranged from a high of approximately $0.98 per gallon to a low of approximately $0.73 per gallon.

Average realized natural gas sales prices for the twelve months ended May 31, 2006 exceeded our historical realized natural gas prices. For example, our average realized natural gas price increased $2.14, or 36%, from $5.97 per MMBtu for the twelve months ended May 31, 2005 to $8.11 per MMBtu for the twelve months ended May 31, 2006. On July 31, 2006, the NYMEX settlement price for September 2006 natural gas deliveries was $8.21 per MMBtu, which was 1% higher than our average natural gas price for the twelve months ended May 31, 2006. Natural gas prices are subject to significant fluctuations, and we cannot assure you that natural gas prices will remain at the high levels recently experienced.

Our Oasis Pipeline, East Texas Pipeline System, ET Fuel System and Houston Pipeline System receive fees for transporting natural gas for our customers. Although a significant amount of the pipeline capacity of the East Texas Pipeline System and various pipeline segments of the ET Fuel System is committed under long-term fee-based contracts, the remaining capacity of our transportation pipelines is subject to fluctuation in demand based on the markets and prices for natural gas and NGLs, which factors may result in decisions by natural gas producers to reduce production of natural gas during periods of lower prices for natural gas and NGLs or may result in decisions by end users of natural gas and NGLs to reduce consumption of these fuels during periods of higher prices for these fuels.

The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:

11

Table of Contents

Our success depends upon our ability to continually contract for new sources of natural gas supply.

In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and asset utilization rates at our treating and processing plants, we must continually contract for new natural gas supplies and natural gas transportation services. We may not be able to obtain additional contracts for natural gas supplies for our natural gas gathering systems, and we may be unable to maintain or increase the levels of natural gas throughput on our transportation pipelines. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity and production of natural gas near our gathering systems or in areas that provide access to our transportation pipelines or markets to which our systems connect. The primary factors affecting our ability to attract customers to our transportation pipelines, including Oasis Pipeline, the East Texas Pipeline System, the ET Fuel System or the Houston Pipeline System, consist of our access to other natural gas pipelines, natural gas markets, natural gas-fired power plants and other industrial end-users and the level of drilling and production of natural gas in areas connected to these pipelines and systems.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity and production generally decrease as oil and natural gas prices decrease. We have no control over the level of drilling activity in our areas of operation, the amount of reserves underlying the wells and the rate at which production from a well will decline, sometimes referred to as the “decline rate.” In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.

A substantial portion of our assets, including our gathering systems and our processing and treating plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. In particular, the Southeast Texas System covers portions of the Austin Chalk, Buda, Georgetown, Edwards, Wilcox and other producing formations in southeast Texas, which we collectively refer to as the Austin Chalk trend. This natural gas producing region has generally been characterized by high initial flow rates followed by steep initial declines in production. Accordingly, our cash flows will also decline unless we are able to access new supplies of natural gas by connecting additional production to these systems.

Our transportation pipelines are also dependent upon natural gas production in areas served by our pipelines or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. A material decrease in natural gas production in our areas of operation or in other areas that are connected to our areas of operation by third party gathering systems or pipelines, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas we handle, which would reduce our revenues and operating income. In addition, our future growth will depend, in part, upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our currently connected supplies.

12

Table of Contents

The volumes of natural gas we transport on our pipelines may be reduced in the event that the prices at which natural gas is purchased and sold at the Waha Hub, the Katy Hub, the Carthage Hub and the Houston Ship Channel Hub, the four major natural gas trading hubs served by our pipelines, become unfavorable in relation to prices for natural gas at other natural gas trading hubs or in other markets as customers may elect to transport their natural gas to these other hubs or markets using pipelines other than those we operate.

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

Our strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, storage, propane 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 diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, the acquisition of additional assets and businesses, stand alone development projects or other transactions that we believe will present opportunities to realize synergies and increase our cash flow.

We may require substantial new capital to finance the future development and acquisition of assets and businesses. Limitations on our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire accretive assets. We may be unable to raise the necessary funds on satisfactory terms, if at all.

Consistent with our acquisition strategy, we are continuously engaged in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve our participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations in which we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We cannot assure you that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us.

In addition, we are experiencing increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in us losing to other bidders more often or acquiring assets at higher prices. Either occurrence would limit our ability to fully execute our growth strategy. Inability to execute our growth strategy may materially adversely impact the market price of our securities.

If we do not make acquisitions on economically acceptable terms, our future growth could be limited.

Historically, our results of operations and our ability to grow and to increase distributions to unitholders has depended principally on our ability to make acquisitions that are accretive to our distributable cash flow per unit. Our acquisition strategy is based, in part, on our expectation of ongoing divestitures of pipeline assets by large industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our business, results of operations, financial condition and cash flows available for distribution to our unitholders.

In addition, we may be unable to make accretive acquisitions for any of the following reasons, among others:

13

Table of Contents

Furthermore, even if we consummate acquisitions that we believe will be accretive, those acquisitions may in fact adversely affect our results of operations or result in no increase or even a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including the risk that we may:

If we consummate future acquisitions, our capitalization and results of operations may change significantly. As we determine the application of our funds and other resources, you will not have an opportunity to evaluate the economics, financial and other relevant information that we will consider.

We depend on certain key producers for our supply of natural gas on the Southeast Texas System, and the loss of any of these key producers could adversely affect our financial results.

For our fiscal year ended August 31, 2005, Anadarko Petroleum Corp. and Chesapeake Energy Corp. supplied us with approximately 42% of the Southeast Texas System’s natural gas supply. We are not the only option available to these producers for disposition of the natural gas they produce. To the extent that these and other producers may reduce the volumes of natural gas that they supply us, we would be adversely affected unless we were able to acquire comparable supplies of natural gas from other producers.

We depend on key customers to transport natural gas on our East Texas Pipeline System and ET Fuel System.

We have entered into nine- and ten-year fee-based transportation contracts with XTO Energy, Inc. pursuant to which XTO Energy has committed to transport certain minimum volumes of natural gas on our pipelines. We have also entered into an eight-year fee-based transportation contract with TXU Portfolio Management Company, L.P., a subsidiary of TXU Corp., which we refer to as TXU Shipper, to transport natural gas on the ET Fuel System to TXU’s electric generating power plants. We have also entered into two eight-year natural gas storage contracts with TXU Shipper to store natural gas at the two natural gas storage facilities that are part of the ET Fuel System. Each of the contracts with TXU Shipper may be extended by TXU Shipper for two additional five-year terms. The failure of XTO Energy or TXU Shipper to fulfill their contractual obligations under these contracts could have a material adverse effect on our cash flow and results of operations if we were not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

14

Table of Contents

Federal, state or local regulatory measures could adversely affect our business.

As a natural gas gatherer and intrastate pipeline company, we are generally exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still significantly affects our business and the market for our products. In recent years, FERC has pursued pro-competitive policies in the regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. The rates, terms and conditions of some of the transportation and storage services we provide on the Oasis Pipeline and the ET Fuel System are subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA. Under Section 311, rates charged for transportation and storage must be fair and equitable amounts. Amounts collected in excess of fair and equitable rates are subject to refund with interest, and the terms and conditions of service, set forth in the pipeline’s Statement of Operating Conditions, are subject to FERC approval. Failure to observe the service limitations applicable to storage and transportation service under Section 311, failure to comply with the rates approved by FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved Statement of Operating Conditions could result in an alteration of jurisdictional status and/or the imposition of administrative, civil and criminal penalties.

Our intrastate natural gas transportation and storage facilities are subject to state regulation in Texas and Louisiana, the states in which we operate these types of pipelines. Our intrastate transportation facilities located in Texas are subject to regulation as common purchasers and as gas utilities by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates we charge for transportation and storage services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, our business may be adversely affected.

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

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

The states in which we conduct operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968, which requires certain pipeline companies to comply with safety standards in constructing

15

Table of Contents

and operating the pipelines, and subjects pipelines to regular inspections. Some of our gathering facilities are exempt from the requirements of this Act. In respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements.

Failure to comply with applicable regulations under the NGA, NGPA, Pipeline Safety Act and certain state laws could result in the imposition of administrative, civil and criminal remedies.

Our business involves hazardous substances and may be adversely affected by environmental regulation.

Our natural gas midstream, transportation and storage, as well as our propane, businesses are subject to stringent federal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits for our operations, result in capital expenditures to manage, limit, or prevent emissions, discharges, or releases of various materials from our pipelines, plants, and facilities, and impose substantial liabilities for pollution resulting from our operations. Several governmental authorities, such as the U.S. Environmental Protection Agency, have the power to enforce compliance with these laws and regulations and the permits issued under them and frequently mandate difficult and costly remediation measures and other actions. Failure to comply with these laws, regulations, and permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of remedial obligations, and the issuance of injunctive relief.

We may incur substantial environmental costs and liabilities because the underlying risk are inherent to our operations. Joint and several, strict liability may be incurred under environmental laws and regulations in connection with discharges or releases of petroleum hydrocarbons or wastes on, under, or from our properties and facilities, many of which have been used for industrial activities for a number of years. Private parties, including the owners of properties through which our gathering systems pass or facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport disposal or remediation requirements could have a material adverse effect on our operations or financial position.

Any reduction in the capacity of, or the allocations to, our shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines, which would adversely affect our revenues and cash flow.

Users of our pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas and NGLs. Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes being transported in our pipelines. Similarly, if additional shippers begin transporting volumes of natural gas and NGLs over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines. Any reduction in volumes transported in our pipelines would adversely affect our revenues and cash flow.

We encounter competition from other midstream, transportation and storage companies and propane companies.

We experience competition in all of our markets. Our principal areas of competition include obtaining natural gas supplies for the Southeast Texas System and natural gas transportation customers for the Oasis Pipeline, the East Texas Pipeline System and the ET Fuel System. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. The Southeast Texas System competes with natural gas gathering and processing systems

16

Table of Contents

owned by Duke Energy Field Services, LLC. The East Texas Pipeline competes with other natural gas transportation pipelines that serve the Bossier Sands area in east Texas and the Barnett Shale area of the Fort Worth Basin in north Texas. The ET Fuel System competes with a number of other natural gas pipelines, including interstate and intrastate pipelines that link the Waha Hub, and the Fort Worth Basin Pipeline competes with other natural gas transportation pipelines serving the Dallas/Ft. Worth area and other pipelines that serve the east central Texas and south Texas markets. Pipelines that we compete with in these areas include those owned by Atmos Energy Corporation, Enterprise Products Partners, L.P., and Enbridge, Inc. Some of our competitors may have greater financial resources and access to larger natural gas supplies than we do.

The acquisition of the Houston Pipeline System increased the number of interstate pipelines and natural gas markets to which we have access and expanded our principal areas of competition to areas such as southeast Texas and the Texas Gulf Coast. As a result of our expanded market presence and diversification, we face additional competitors, such as major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas, that may have greater financial resources and access to larger natural gas supplies than we do.

Our propane business competes with a number of large national and regional propane companies and several thousand small independent propane companies. Because of the relatively low barriers to entry into the retail propane market, there is potential for small independent propane retailers, as well as other companies that may not currently be engaged in retail propane distribution, to compete with our retail outlets. As a result, we are always subject to the risk of additional competition in the future. Generally, warmer-than-normal weather further intensifies competition. Most of our propane retail branch locations compete with several other marketers or distributors in their service areas. The principal factors influencing competition with other retail propane marketers are:

Expanding our business by constructing new pipelines and treating and processing facilities subjects us to risks.

One of the ways that we expect to grow our business is through the construction of additions to our existing gathering, compression, treating, processing and transportation systems. The construction of a new pipeline or the expansion of an existing pipeline, by adding additional compression capabilities or by adding a second pipeline along an existing pipeline, and the construction of new processing or treating facilities, involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital that we will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately following the completion of particular projects. For instance, if we build a new pipeline, the construction will occur over an extended period of time, but we may not materially increase our revenues until long after the project’s completion. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, new facilities may be unable to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial

17

Table of Contents

condition. As a result, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity in the areas proposed to be serviced by the project as well as our ability to obtain commitments from producers in this area to utilize the newly constructed pipelines.

We are exposed to the credit risk of our customers, and an increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

The risks of nonpayment and nonperformance by our customers are a major concern in our business. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any substantial increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

We may be unable to bypass the La Grange processing plant, which could expose us to the risk of unfavorable processing margins.

Because of our ownership of the Oasis Pipeline, we can generally elect to bypass the La Grange processing plant when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the Southeast Texas System with lean gas transported on the Oasis Pipeline. In some circumstances, such as when we do not have a sufficient amount of lean gas to blend with the volume of rich gas that we receive at the La Grange processing plant, we may have to process the rich gas. If we have to process when processing margins are unfavorable, our results of operations will be adversely affected.

We may be unable to retain existing customers or secure new customers, which would reduce our revenues and limit our future profitability.

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets we serve.

For our fiscal year ended August 31, 2005, approximately 33% of our sales of natural gas were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are increasingly reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are many companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

Our storage business depends on neighboring pipelines to transport natural gas.

To obtain natural gas, our storage business depends on the pipelines to which they have access. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on those pipelines or adverse change in their terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our facilities and a corresponding material adverse effect on our storage revenues. In addition, the rates charged by those interconnected pipelines for transportation to and from our facilities affect the utilization and value of our storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.

18

Table of Contents

Our pipeline integrity program may cause us to incur significant costs and liabilities.

In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The final rule was effective as of January 14, 2004. Based on the results of our current pipeline integrity testing programs, we estimate that compliance with this final rule for our existing transportation assets will result in capital costs of $23.7 million during the period between 2006 to 2008, as well as operating and maintenance costs of $24.7 million during that three-year period. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

Since weather conditions may adversely affect demand for propane, our financial conditions may be vulnerable to warm winters.

Weather conditions have a significant impact on the demand for propane for heating purposes because the majority of our customers rely heavily on propane as a heating fuel. Typically, we sell approximately two-thirds of our retail propane volume during the peak-heating season of October through March. Our results of operations can be adversely affected by warmer winter weather which results in lower sales volumes. In addition, to the extent that warm weather or other factors adversely affect our operating and financial results, our access to capital and our acquisition activities may be limited. Variations in weather in one or more of the regions where we operate can significantly affect the total volume of propane that we sell and the profits realized on these sales. Agricultural demand for propane may also be affected by weather, including periods of unseasonably cold or hot periods or dry weather conditions which may impact agricultural operations.

Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect our profit margins.

The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices over supply costs. As a result, our profitability is sensitive to changes in energy prices, and in particular, changes in wholesale prices of propane. When there are sudden and sharp increases in the wholesale cost of propane, we may be unable to pass on these increases to our customers through retail or wholesale prices. Propane is a commodity and the price we pay for it can fluctuate significantly in response to changes in supply or other market conditions over which we have no control. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce our gross profits and could, if continued over an extended period of time, reduce demand by encouraging our retail customers to conserve their propane usage or convert to alternative energy sources.

Our results of operations and our ability to make distributions or pay interest or principal on debt securities could be negatively impacted by price and inventory risk related to our propane business and management of these risks.

We generally attempt to minimize our cost and inventory risk related to our propane business by purchasing propane on a short-term basis under supply contracts that typically have a one-year term and at a cost that fluctuates based on the prevailing market prices at major delivery points. In order to help ensure adequate supply sources are available during periods of high demand, we may purchase large volumes of propane during periods of low demand or low price, which generally occur during the summer months, for storage in our facilities, at major storage facilities or for future delivery. This strategy may not be effective in limiting our cost and inventory risks if, for example, market, weather or other conditions prevent or allocate the delivery of physical product during periods of peak demand. If the market price falls below the cost at which we made such purchases, it could adversely affect our profits.

19

Table of Contents

Some of our propane sales are pursuant to commitments at fixed prices. To mitigate the price risk related to our anticipated sales volumes under the commitments, we may purchase and store physical product and/or enter into fixed price over-the-counter energy commodity forward contracts and options. Generally, over-the-counter energy commodity forward contracts have terms of less than one year. We enter into such contracts and exercise such options at volume levels that we believe are necessary to manage these commitments. The risk management of our inventory and contracts for the future purchase of product could impair our profitability if the customers do not fulfill their obligations.

We also engage in other trading activities, and may enter into other types of over-the-counter energy commodity forward contracts and options. These trading activities are based on our management’s estimates of future events and prices and are intended to generate a profit. However, if those estimates are incorrect or other market events outside of our control occur, such activities could generate a loss in future periods and potentially impair our profitability.

We are dependent on our principal propane suppliers, which increases the risk of an interruption in supply.

During fiscal 2005, we purchased approximately 23.7% of our propane from Enterprise Products Operating L.P., approximately 20.6% of our propane from Dynegy Liquids Marketing and Trade and approximately 23% of our propane from M-P Energy Partnership, the Canadian partnership in which we own a 60% interest. In addition, Titan purchases 100% of its propane from Enterprise pursuant to an agreement that expires in 2010. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be adversely affected. Supply from Canada is subject to the additional risk of disruption associated with foreign trade such as trade restrictions, shipping delays and political, regulatory and economic instability.

Historically, a substantial portion of the propane that we purchase has originated from one of the industry’s major markets located in Mt. Belvieu, Texas and has been shipped to us through major common carrier pipelines. Any significant interruption in the service at Mt. Belvieu or other major market points, or on the common carrier pipelines we use, would adversely affect our ability to obtain propane.

Competition from alternative energy sources may cause us to lose propane customers, thereby reducing our revenues.

Competition in our propane business from alternative energy sources has been increasing as a result of reduced regulation of many utilities. Propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a less expensive source of energy than propane. The gradual expansion of natural gas distribution systems and the availability of natural gas in many areas that previously depended upon propane could cause us to lose customers, thereby reducing our revenues. Fuel oil also competes with propane and is generally less expensive than propane. In addition, the successful development and increasing usage of alternative energy sources could adversely affect our operations.

Energy efficiency and technological advances may affect the demand for propane and adversely affect our operating results.

The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has decreased the demand for propane by retail customers. Stricter conservation measures in the future or technological advances in heating, conservation, energy generation or other devices could adversely affect our operations.

Tax Risks

For a general discussion of the expected federal income tax consequences of owning and disposing of our securities, see “Material Income Tax Considerations.”

20

Table of Contents

The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to unitholders.

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 IRS on this or any other matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation personally as an entity.

If we were so treated as a corporation, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35% and we would likely pay additional state income taxes as well. Distributions to unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to unitholders. Because an additional, material tax would be imposed upon us in that case, our cash available for distribution to unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the available cash distributions to the unitholders, likely causing a substantial reduction in the value of our common units.

In addition, various states may evaluate ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us personally as an entity, the cash available for distribution to you would be reduced. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that causes us to be treated as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution and the target distribution levels will be adjusted to reflect that impact on us.

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

We have not requested a ruling from the IRS with respect to any matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain our counsel’s conclusions or the positions we take. A court may not concur with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely affect the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly borne by our unitholders and our general partner since such costs will reduce the amount of cash available for distribution.

Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from the taxation of their share of our taxable income. In such case, Unitholders would still be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income regardless of the amount, if any, of any cash distributions they receive from us.

21

Table of Contents

Only calendar year taxpayers may become partners.

Only calendar year taxpayers may purchase common units. Any unitholder who is not a calendar year taxpayer will not be admitted to Energy Transfer Partners, L.P. as a partner, will not be entitled to receive distributions or federal income tax allocations from Energy Transfer Partners, L.P. and may only transfer these common units to a purchaser or other transferee.

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

Unitholders who sell common units will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income allocated for a common unit that decreased a 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 is less than his original cost. A substantial portion of the amount the unitholder realizes, whether or not representing gain, will likely be ordinary income to the unitholder. Should the IRS successfully contest some positions we take, a unitholder could recognize more gain on the sale of common units than would be the case under those positions, without the benefit of decreased income in prior years. Also, unitholders who sell common units may incur a tax liability in excess of the amount of cash they receive from the sale.

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

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, may be taxable to them as “unrelated business taxable income”. Distributions to non-U.S. persons will be reduced by withholding taxes, at the highest applicable rate, and non-U.S. persons will be required to file federal income tax returns and generally pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

We will treat each purchaser of 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 the units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that do not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the 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. Please read “Material Income Tax Considerations—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units.”

Unitholders likely will be subject to state and local taxes in states where they do not live as a result of an investment in the units.

In addition to federal income taxes, the unitholders may be subject to other taxes, including state and local 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 now or in the future, even if they do not live in any of those jurisdictions. We presently have business operations in 40 states. In the future, we may acquire property or do business in other states or in foreign jurisdictions. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each unitholder to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in us.

22

Table of Contents

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. Please read “Material Income Tax Considerations—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for tax purposes.

23

Table of Contents